Philippines: Power Transmission Reinforcement Project

Home , Balayan, Leyte (province), Philippine peso

Completion Report

Project Number: 31433 Loan Number: 1590-PHI August 2006

CURRENCY EQUIVALENTS Currency Unit – Peso (P)

At Appraisal At Project Completion 18 November 1997 29 April 2006 P1.00 = $0.0294 $0.0193 $1.00 = P34.05 P51.775

ABBREVIATIONS

ADB – Asian Development Bank DENR – Department of Environment and Natural Resources DSCR – debt service coverage ratio EIRR – economic internal rate of return EPIRA – Electric Power Industry Reform Act ERC – Energy Regulatory Commission FIRR – financial internal rate of return IPP – independent power producer ICC – Investment Coordination Committee NPC – National Power Corporation O&M – operation and maintenance PCB – power circuit breaker PCR – project completion report PMO – project management office PSALM – Power Sector Assets and Liabilities Management Corporation RORB – return of rate base ROW – right-of-way Transco – National Transmission Corporation

WEIGHTS AND MEASURES

GWh (gigawatt-hour) – equivalent to 1,000 megawatt-hour Km (kilometer) – equivalent to 1,000 meters kV (kilovolt) – unit of electrical power equal to 1,000 volts kWh (kilowatt-hour) – unit of energy MVA (megavolt-ampere) – unit of apparent power MW (megawatt) – unit of power, equal to 1 million watts

NOTES

(i) The fiscal year of the Government and NPC ends on 31 December.

(ii) In this report, "$" refers to US dollars.

Vice President C. L. Greenwood, Jr., Operations Group 2 Director General R. M. Nag, Southeast Asia Department Director J. R. Cooney, Infrastructure Division, Southeast Asia Department

Team leader Y. Zhai, Principal Energy Specialist, Southeast Asia Department Team members H. Tabin, Assistant Project Analyst, Southeast Asia Department Y. Tsujiki, Financial Specialist, Southeast Asia Department

CONTENTS

Page

BASIC DATA i MAPS I. PROJECT DESCRIPTION 1 II. EVALUATION OF DESIGN AND IMPLEMENTATION 1 A. Relevance of Design and Formulation 1 B. Project Outputs 2 C. Project Costs 4 D. Disbursements 4 E. Project Schedule 4 F. Implementation Arrangements 5 G. Conditions and Covenants 5 H. Consultant Recruitment and Procurement 7 I. Performance of Consultants, Contractors, and Suppliers 7 J. Performance of the Borrower and the Executing Agency 8 K. Performance of the Asian Development Bank 8 III. EVALUATION OF PERFORMANCE 9 A. Relevance 9 B. Effectiveness in Achieving Outcome 9 C. Efficiency in Achievement of Outputs and Purpose 9 D. Preliminary Assessment of Sustainability 10 E. Environmental, Sociocultural, and Other Impacts 11 IV. OVERALL ASSESSMENT AND RECOMMENDATIONS 12 A. Overall Assessment 12 B. Lessons Learned 12 C. Recommendations 13 APPENDIXES 1. Project Framework 15 2. Chronology of Events 17 3. Actual Disbursements 21 4. Implementation Schedule (Appraisal vs. Actual) 22 5. Status of Compliance with Loan Covenants 23 6. Financial and Economic Analysis of the Project 26

BASIC DATA

A. Loan Identification

1. Country Philippines 2. Loan Number 1590-PHI 3. Project Title Power Transmission Reinforcement Project 4. Borrower National Power Corporation 5. Executing Agency National Transmission Corporation 6. Amount of Loan $191.4 million 7. Project Completion Report PCR: PHI 949 Number

B. Loan Data 1. Appraisal – Date Started 11 August 1997 – Date Completed 4 September 1997

2. Loan Negotiations – Date Started 10 November 1997 – Date Completed 18 November 1997

3. Date of Board Approval 16 December 1997

4. Date of Loan Agreement 21 January 1998

5. Date of Loan Effectiveness – In Loan Agreement 21 April 1998 – Actual 3 April 1998 – Number of Extensions 0

6. Closing Date – In Loan Agreement 30 June 2002 – Actual 1 April 2005 – Number of Extensions 2

7. Terms of Loan – Interest Rate Pool-based variable lending rate system for US dollar loans, and subject to ADB’s standard commitment fees – Maturity (years) 20 – Grace Period (years) 4

8. Disbursements a. Dates Initial Disbursement Final Disbursement Time Interval

1 December 1998 1 April 2005 76 months

Effective Date Original Closing Date Time Interval

3 April 1998 30 June 2002 51 months

b. Amount ($ million) Category Last Net or Original Revised Amount Amount Amount Undisbursed Subloan Allocation Allocation Canceled Available Disbursed Balance

OCR 191.4 43.3 145.6 43.3 43.3 2.5a

Total 191.4 43.3 145.6 43.3 43.3 2.5 OCR = ordinary capital resources. a Canceled on loan closure, 1 April 2005.

C. Project Data

1. Project Cost ($ million)

Cost Appraisal Estimate Actual

Foreign Exchange Cost 211.0 116.2 Local Cost 93.2 83.7 Total 304.2 199.9

2. Financing Plan ($ million)

Cost Appraisal Estimate Actual Implementation Costs ADB-Financed 167.3 35.2 Borrower-Financed 69.2 90.3 Other External Financing 43.6 66.3 Total 280.1 191.8 IDC Costs ADB-Financed 24.1 8.1 Borrower-Financed 0.0 Total 304.2 199.9 ADB = Asian Development Bank, IDC = interest during construction.

iii

3. Cost Breakdown By Project Component ($ million) Item Appraisal Estimate Actual ($ million equivalent) ($ million equivalent) Foreign Local Total Foreign Local Total Part A: Leyte-Cebu uprating 104.5 8.1 112.6 61.1 13.0 74.1 Part B: Batangas reinforcement 61.0 71.4 132.4 46.0 70.5 116.5 Part C: Consultancy 0.8 0.2 1.0 1.0 0.2 1.2 Subtotal 166.3 79.7 246.0 108.1 83.7 191.8 Contingencies 20.6 13.5 34.1 IDC on ADB Loan 24.1 24.1 8.1 8.1 Total 211.0 93.2 304.2 116.2 83.7 199.9

IDC = interest during construction. Source: Asian Development Bank estimates.

4. Project Schedule Item Appraisal Estimate Actual Part A: Leyte-Cebu submarine interconnection a. Uprating of Leyte-Cebu Interconnection Project Bid Opening 1 October 1998 30 July 2003 Contract Effectiveness 30 April 1999 June 2004 Interconnection Completion 23 October 2000 October 2005 b. Repair of Damaged Leyte-Cebu Submarine Cables 3 and 4 (Phase I)—Turnkey Bid Opening 31 August 2000 31 August 2000 Contract Effectiveness 28 February 2002 16 July 2002 Repair Completion 27 August 2002 2 October 2002

Part B: Batangas transmission reinforcement a. Supply and Delivery of Substation Equipment

Substation Equipment for San Pascual and Sta. Rita Bid Opening 30 April 1998 29 January 1999 Contract Effectiveness 30 December 1998 14 February 2002 Contract Completion 27 August 2002 12 October 2002

Batangas Substation 30 April 1998 29 January 1999 Bid Opening 30 December 1998 12 December 2001 Contract Effectiveness 27 August 1999 9 August 2002 Contract Completion

Makban A Switchyard 30 April 1998 29 January 1999 Bid Opening 30 December 1998 14 February 2002 Contract Effectiveness 27 August 1999 12 October 2002 Contract Completion

Biñan Substation 30 April 1998 29 January 1999 Bid Opening 30 December 1998 12 December 2001 Contract Effectiveness 27 August 1999 9 August 2002 Contract Completion

Telecommunication and Protection System 30 April 1998 29 January 1999 Bid Opening 30 December 1998 29 October 2001 Contract Effectiveness 27 August 1999 26 June 2002 Contract Completion

Item Appraisal Estimate Actual b. Supply and Delivery of Transmission Line Materials Steel Tower Structure San Pascual Cogeneration Transmission Lines Bid Opening 30 April 1998 6 May 1999 Contract Effectiveness 31 December 1998 9 July 2001 Contract Completion 29 July 1999 4 February 2002

Power Conductor, Overhead Ground Wire, Guy Wire San Pascual Cogeneration Transmission Lines Bid Opening 30 April 1998 6 May 1999 Contract Effectiveness 31 December 1998 18 July 2001 Contract Completion 27 October 1999 14 May 2002

Insulators and Insulators Assemblies San Pascual Cogeneration Transmission Lines Bid Opening 30 April 1998 6 May 1999 Contract Effectiveness 31 December 1998 29 October 2001 Contract Completion 29 June 1999 27 April 2002

Line Hardware and Accessories San Pascual Cogeneration Transmission Lines Bid Opening 30 April 19998 6 May 1999 Contract Effectiveness 31 December 1998 22 January 2001 Contract Completion 29 June 1999 21 July 2001

Composite Optical Group Wire San Pascual Cogeneration Transmission Lines Bid Opening 30 April 1998 6 May 1999 Contract Effectiveness 31 December 1998 31 January 2001 Contract Completion 29 June 1999 30 July 2001

5. Project Performance Report Ratings Ratings

Development Implementation Implementation Period Objectives Progress From 1 October 2000 to 31 December 2000 Satisfactory Partly Satisfactory From 1 January 2001 to 30 June 2001 Satisfactory Partly Satisfactory From 1 July 2001 to 31 December 2001 Satisfactory Partly Satisfactory From 1 January 2002 to 31 March 2002 Satisfactory Partly Satisfactory From 1 April 2002 to 30 June 2002 Satisfactory Partly Satisfactory From 1 July 2002 to 30 September 2002 Satisfactory Partly Satisfactory From 1 October 2002 to 31 December 2002 Satisfactory Partly Satisfactory From 1 January 2003 to 31 March 2003 Satisfactory Partly Satisfactory From 1 April 2003 to 30 June 2003 Satisfactory Partly Satisfactory

Ratings

Development Implementation Implementation Period Objectives Progress From 1 July 2003 to 30 September 2003 Satisfactory Partly Satisfactory From 1 October 2003 to 31 December 2003 Satisfactory Partly Satisfactory From 1 January 2004 to 29 February 2004 Satisfactory Partly Satisfactory From 1 March 2004 to 31 March 2004 Satisfactory Satisfactory From 1 April 2004 to 30 June 2004 Satisfactory Partly Satisfactory From 1 July 2004 to 30 September 2004 Satisfactory Partly Satisfactory From 1 October 2004 to 31 December 2004 Satisfactory Partly Satisfactory From 1 January 2005 to 31 March 2005 Satisfactory Partly Satisfactory From 1 April 2005 to 30 April 2005 Satisfactory Partly Satisfactory

D. Data on Asian Development Bank Missions No. of No. of Specialization Name of Mission Date Persons Person- of Members1 Days Fact-Finding 29 April–19 May 1997 6 45 a, b, d, e, h Appraisal 11 August–4 September 1997 9 90 a, b, c, d, e, f, h Inception 17 April 1997 5 5 a, b, e Review 9–20 October 2000 3 20 a, g, i Review 15–23 October 2001 3 15 a, g, i Review 12–16 August 2002 3 15 a, g, i Project Completion Review 10–11 and 17–19 April 2006 3 15 a, g, i Note: The project completion report was prepared by Yongping Zhai, Principal Energy Specialist. 1 a - engineer, b - financial analyst, c - counsel, d - programs officer, e – environment specialist, f – social development specialist, g – energy specialist, h - young professional, i – project analyst.

Map 1

o o o 118 00'E 126 00'E 124 00'E 125 o 00'E PHILIPPINES

16 o 00'N 16 o 00'N LUZON PHILIPPINES Manila POWER TRANSMISSION REINFORCEMENT PROJECT LEYTE-- CEBU INTERCONNECTION UPRATING VISAYAS (as completed)

Project Location 8o 00'N 8o 00'N Maripipi Island MINDANAO Visayas Sea BILIRAN

118o 00'E 126o 00'E Naval o o 11 35'N Samar Sea 11 35'N 120 o 10'E

Babatnon Tabango

Carigara Barugo Bantayuan Island Daan Bantay Talisay Jaro TACLOBAN

Bantayan Palo Medellin Tongonan Philippine National Oil Company San Remegio Ormoc Tanauan Bogo Ormoc Isabel L E Y T E Albuera

Tabuelan Bordon Leyte Gulf Pacijan Island Abuyog Tuburan Bogod t Catmon

i Baybay

Tudela r Poro

t Asturias Carmen C E B U

S Danao

Inopacan

Compostela n Compostela Hinunangan Hilongos o Banilad Camotes Sea SOUTHERN n Toledo Liloan

CEBU a Bato LEYTE Hinundayan Mactan T Minglanilla Mactan Island Naga Maasin San Fernando

Carcar N

o o 10 00'N 10 00'N 0 5 10 20 30 40

Kilometers

National Capital City/Municipality Geothermal Power Plant 230kV Substation Cable Marine Station 230 kV Transmission Line 230 kV Submarine Cable Provincial Boundary Boundaries are not necessarily authoritative

o o 124 00'E 125 00'E

06-1425a HR Map 2

o o 118 00'E 126o 00'E 121 10'E PHILIPPINES

PHILIPPINES 16 o 00'N 16 o 00'N LUZON POWER TRANSMISSION Manila REINFORCEMENT PROJECT Project Location BATANGAS TRANSMISSION REINFORCEMENT VISAYAS (as completed)

RIZAL 8o 00'N 8o 00'N MINDANAO Dasmariñas-Biñan 230 kV Transmission Line Jalajala Biñan Dasmariñas

118o 00'E 126o 00'E Carmona Sta. Rosa Calamba Tower Laguna de Bay Lumban Sta. Cruz Makban-Biñan Silang 230 kV Transmission Line CAVITE

Los Baños LAGUNA Calaca-Dasmariñas 230 kV Transmission Line SAN PABLO (OECF Funded)

Tagaytay Calaca-Biñan Makban 230 kV Transmission Line Geothermal Talisay Power Plant

o o 14 00'N 14 00'N QUEZON Taal Lake Lipa

Calaca Calaca BATANGAS

Sta. Rita-Calaca Makban-Batangas 230 kV Transmission Line 230 kV Transmission Line (FGHC Funded) Taal

Batangas

San Lorenzo Sta. Rita National Capital Balayan Bay Sta. Rita-San Lorenzo City/Municipality 230 kV Transmission Line BATANGAS Power Plant Substation Batangas Project Transmission Line Bay Existing Transmission Line N Provincial Boundary Boundaries are not necessarily authoritative.

0 5 10

Kilometers

o 121 10'E

06-1425b HR

I. PROJECT DESCRIPTION

1. When the Power Transmission Reinforcement Project (the Project) was being processed, the Philippine economy was projected to grow quickly. The economic expansion was expected to spur electricity demand growth of about 10% per year from 1997 to 2010, even with demand- side management programs. To address this rising demand, additional installed generating capacity was needed with corresponding power transmission lines to (i) evacuate output of independent power producers (IPP), (ii) provide open access to stimulate competition, and (iii) ensure the reliability and stability of the power supply. As the transmission reinforcement and expansion program require large investments, continued Asian Development Bank (ADB) assistance to National Power Corporation (NPC) was needed until privatization initiatives could yield sufficient equity and other funds.

2. ADB approved the Project on 16 December 1997. 1 NPC is the Borrower, the Government of the Philippines is the Guarantor, and the National Transmission Corporation (Transco) is the Executing Agency. The Project had two components. First, it was to reinforce and expand the interconnection between the island grids of Leyte and Cebu to increase the utilization of geothermal power from Leyte. Second, the Project was to reinforce and expand the transmission system in Luzon to accommodate the IPPs, and facilitate a functioning and competitive market in power generation. The Project’s outputs as indicated in the Report and Recommendation of the President included:

(i) Leyte-Cebu interconnection uprating, (ii) San Pascual-Batangas 230-kilovolt (kV) transmission line, (iii) San Pascual-Sta. Rita 230 kV transmission line, (iv) Batangas-Makban-Biñan 230 kV transmission line, (v) Makban A-Makban C 230 kV transmission line, (vi) Calaca-Dasmariñas 230 kV transmission line, (vii) Sta. Rita-Calaca 230 kV transmission line, and (viii) Consulting services for engineering design and construction supervision of the Leyte-Cebu interconnection uprating.

II. EVALUATION OF DESIGN AND IMPLEMENTATION

A. Relevance of Design and Formulation

3. The Project was in line with ADB’s operational strategy at appraisal. It continued to be relevant through its support for economic growth, which is a key thematic priority for ADB assistance to the Philippines. The Project was also an integral component of the country’s transmission development program, which was designed to meet the system requirements for the increased power generation to cope with the anticipated growth in demand for power.

4. At appraisal, however, the effect of the Asian financial crisis on the Philippine economy was not appreciated fully. The appraisal report indicated that power supply would increase by about 10% per year in 1997–2010. Based on an econometric analysis as a function of regional domestic product, the projected peak demand in 2004 for the Luzon, Visayas, and Mindanao grids would be 9,303 megawatts (MW), 1,496 MW, and 1,964 MW, respectively. Based on this

1 ADB. 1997. Report and Recommendation of the President to the Board of Directors on a Proposed Loan to the National Power Corporation for the Power Transmission Reinforcement Project in the Republic of the Philippines. Manila (Loan 1590-PHI, for $191.4 million).

2 analysis, two components were proposed: (i) to double the transfer capacity from 200 MW to 400 MW of the Leyte-Cebu interconnection (Part A), and (ii) to reinforce and expand the Batangas transmission system to evacuate an additional 1,650 MW from IPP power plants (Part B). As envisaged, both components would be completed by the end of 2001.

5. The implementation of the Project was delayed—by about 5 years for Part A, and about 6 years for ADB-financed components of Part B. However, the overly optimistic demand forecast tempered the negative impacts of these delays. In 2004, the actual peak demand was only 6,728 MW for Luzon (38% below forecast), 1,063 MW for Visayas (40% below forecast), and 1,278 MW for Mindanao (53% below forecast). During project implementation, several changes were made to ADB-financed components. For Part A, ADB canceled the loan allocation for the Leyte-Cebu interconnection uprating in August 2002 in response to the Government’s unilateral decision to rebid the contract after ADB’s Procurement Committee had approved Transco’s recommendation. This component eventually was rebid and financed by commercial sources. Instead, ADB financed the repair work of the damaged Leyte-Cebu interconnection submarine cables as a minor change in scope. Further, ADB approved another minor change in scope in June 2002 to reroute an 18-kilometer (km) portion of the proposed Makban-Biñan transmission lines to be implemented under Component B3 (the Calamba-Biñan section) to minimize resettlement problems. Due to inadequate loan allocation, ADB also agreed that loan savings from the Electricity Market and Transmission Development Project, 2 cofinanced with Japan Bank for International Cooperation, could be used to finance the rerouted Calamba-Biñan section. Procurement for the Calamba-Biñan transmission line was in progress during the Project Completion Report (PCR) Mission. Its completion is expected by June 2008. Transco used the tower and line materials envisaged for the original route of Calamba-Biñan section to upgrade the 14.5 km Damarinas-Biñan transmission lines, which were completed in January 2005. As a result, the transfer capacity of Damarinas-Biñan transmission lines increased from 300 MW to 1,200 MW, boosting the dispatch of the Ilijan gas-fired facility in Batangas from 600 MW to 1,200 MW. The completion of Damariñas-Biñan transmission lines also minimized the negative impacts of the delays in completing the Batangas-Makban-Biñan 230 kV transmission lines.

6. Overall, the technical design and formulation of the Project had weaknesses, as they were based on inaccurate demand forecasts and underestimated right-of-way (ROW) issues. Nevertheless, lower-than-expected demand growth and a change in scope that allowed the upgrading of the Damariñas-Biñan transmission line minimized the negative impacts of the implementation delays.

B. Project Outputs

7. The PCR Mission assessed the Project’s immediate objectives against appraisal targets, as far as applicable (Appendix 1). The chronology of events of the Project is in Appendix 2. In summary, the project outputs anticipated at appraisal are compared with those achieved at completion (Table 1).

2 ADB. 2002. Report and Recommendation of the President to the Board of Directors on a Proposed Loan to the National Power Corporation for the Electricity Market and Transmission Development Project and Technical Assistance Grant to the Republic of the Philippines for the Transition to Competitive Electricity Market. Manila (Loan 1984-PHI, for $40.0 million, approved on 19 December).

Table 1: Project Outputs, Appraisal vs. Completion Appraisal Completion Remarks Part A: Uprating of Leyte-Cebu Completed on 25 October 2005. Dropped from ADB submarine cable and associated financing (para.5), this transmission and substation component was financed by expansion. commercial loans instead. B1: San Pascual-Batangas 230 kV San Lorenzo-Batangas 230 kV San Pascual power plant transmission line. transmission line, 8.91 km, was not built. Instead, a completed March 2005. 500 MW San Lorenzo power plant was built. B2: San Pascual-Sta. Rita 230 kV Not required. San Pascual power plant transmission line. was not built.

B3: Batangas-Makban-Biñan 230 kV Line materials procured under Line materials procured and transmission line. ADB financing, Batangas-Makban delivered by the end of line is scheduled for completion 2003 under ADB financing; by September 2006; Makban- erection will be completed Biñan line was built up to by September 2006. The Calamba. The transmission line new transmission line from from Makban to Biñan is Calamba to Biñan has been energized using a portion of an included for financing under existing transmission line from Loan 1984-PHI. Calamba to Biñan. B4: Makban A-Makban C 230 kV Line materials procured under Line materials procured and transmission line. ADB financing; erection will be delivered by the end of completed by September 2006. 2003 under ADB financing; erection will be completed by September 2006. B5: Calaca-Dasmariñas 230 kV Completed as appraised in Japan Bank for transmission line. October 1998. International Cooperation financed this component. B6: Sta. Rita-Calaca 230 kV Completed as appraised in First Gas Holdings transmission line. August 1999. Corporation financing financed this component. C: Consulting Services. Service completed in October Although Part A was not 2005. financed by ADB, the consultant supervised the implementation of Part A as envisaged. Dasmariñas-Biñan 230 kV Completed in January 2005. This component was transmission line. implemented using the materials for the Calamba- Biñan transmission line, which was part of the original Batangas-Makban- Biñan 230 kV transmission line. Repair of Leyte-Cebu submarine Completed in October 2002. This component was cables. implemented as a minor change in scope. ADB = Asian Development Bank, km = kilometer, kV = kilovolt, MW = megawatt. Source: Asian Development Bank.

C. Project Costs

8. At appraisal, the project cost was estimated at $304.2 million, of which $211.0 million was foreign exchange cost (Table 2). ADB’s loan was allocated to the foreign exchange costs of parts A and C of the Project, as well as some subcomponents of Part B. NPC financed the local costs of the Project. At completion, the actual cost of the Project was $199.9 million equivalent—66% of the estimated cost—including $116.2 million equivalent in foreign exchange costs and $83.7 million equivalent in local currency costs. The cost for Part A, the Leyte-Cebu interconnection uprating, was $74.1 million, compared with an appraisal estimate of $112.6 million. Substantial savings also were realized for the supply of line materials and substation equipment under Part B, mainly because of lower-than-expected contract prices resulting from fierce competition under international competitive bidding.

Table 2: Estimated and Actual Project Costs Item Appraisal Estimate Actual ($ million equivalent) ($ million equivalent) Foreign Local Total Foreign Local Total Part A: Leyte-Cebu uprating 104.5 8.1 112.6 61.1 13.0 74.1 Part B: Batangas reinforcement 61.0 71.4 132.4 46.0 70.5 116.5 Part C: Consulting 0.8 0.2 1.0 1.0 0.2 1.2 Subtotal 166.3 79.7 246.0 108.1 83.7 191.8 Contingencies 20.6 13.5 34.1 IDC on ADB Loan 24.1 24.1 8.1 8.1 Total 211.0 93.2 304.2 116.2 83.7 199.9

ADB = Asian Development Bank, IDC=interest during construction. Source: ADB estimates.

D. Disbursements

9. The ADB loan originally was to be fully disbursed by 30 June 2002. The actual yearly disbursements are in Appendix 3. The closing date was extended twice, until 31 December 2004, due to implementation delays. During project implementation, as soon as savings were realized due to a change in scope for ADB-financed components and lower-than-expected project costs, NPC requested cancellation of the savings to avoid payment of commitment charges. Therefore, $145.6 million was canceled before loan closing. The loan account was closed on 1 April 2005, and the undisbursed balance of $2.5 million was canceled. Due to the cancellation of Part A and lower-than-expected project costs for Part B, actual disbursements of the loan was $43.3 million—or 22.6% of ADB’s original $191.4 million loan.

E. Project Schedule

10. Appendix 4 compares the appraisal schedule with the actual project time frame. As envisaged, implementation of Part A, the Leyte-Cebu interconnection uprating, was to be completed by July 2000. However, it was not finished until October 2005. The main reason for the delay was the disagreement with the Government over the procurement process, which eventually prompted ADB to cancel funding for this component. For Part B, the components financed by Japan Bank for International Cooperation and First Gas Holdings Corporation—B5 and B6—were completed substantially in accordance with the appraisal estimates (construction was already in progress at appraisal). Further, ROW issues seriously delayed the implementation of other components under Part B. Although the line materials and substation

5 equipment under ADB-financed supply contracts were delivered by the end of 2002, the erection work under Transco’s financing will not be completed until September 2006.

F. Implementation Arrangements

11. NPC is the Borrower, and the Government of the Philippines is the Guarantor. As envisaged at appraisal, NPC established a project management office (PMO), headed by a qualified and experienced director, to coordinate project activities. A project manager also was designated to oversee project implementation in the field, assisted by site managers responsible for each component. In accordance with the Electric Power Industry Reform Act (EPIRA) of 2001, Transco took over loan administration and project implementation from NPC in 2002. The relevant PMO staff, including the director, were transferred to Transco. Although these arrangements complied with ADB requirements, the PMO did not have the authority to ensure timely implementation of the Project. Many problems, such as procurement and ROW issues, were beyond its control.

G. Conditions and Covenants

12. Appendix 5 shows the status of NPC’s compliance with major project covenants, including two key financial agreements:

(i) A debt service coverage ratio (DSCR) of at least 1.3 from 1995. The Northern Luzon Transmission and Generation Project3 subsequently modified the DSCR requirement to 1.0 for 1995–1999, and not less than 1.3 afterward.

(ii) A return on rate base (RORB) of at least 8% from 1994. The Power Transmission Reinforcement Project4 subsequently modified the RORB requirement to 7% for 1998, and 8% afterward.

13. NPC submitted quarterly progress reports, as well as regular audited financial statements, throughout project implementation. The quality of these reports was satisfactory. Independent auditors, in accordance with Section 4.07 of the Loan Agreement, audited NPC’s accounts and financial statements annually, and provided opinions on compliance with the loan covenants.

14. NPC did not comply with the DSCR and RORB covenants during 1999–2004 (Table 3). The major problems that affected NPC’s financial position were (i) surplus capacity caused by completion of high-priced IPP contracts, with take-or-pay provisions in foreign exchange, that were arranged before the Asian financial crisis; (ii) lower-than-expected electricity sales; (iii) inadequate equity contributions from the Government; and (iv) increased costs of debt service and IPP payments after the Philippine peso depreciated.

3 ADB. 1995. Report and Recommendation of the President to the Board of Directors on a Proposed Loan to the National Power Corporation and a Technical Assistance Grant to the Republic of the Philippines for the Northern Luzon Transmission and Generation Project in the Republic of the Philippines. Manila (Loan 1398-PHI, for $244.0 million, approved on 2 November). 4 ADB. 1997. Report and Recommendation of the President to the Board of Directors on a Proposed Loan to the National Power Corporation for the Power Transmission Reinforcement Project in the Republic of the Philippines. Manila (Loan 1590-PHI, for $191.4 million, approved on 16 December).

Table 3: NPC Financial Performance (1999–2004) Indicators 1999 2000 2001 2002 2003 2004 Sales (GWh) 36,987 37,320 37,042 34,369 34,396 36,596 Sales Growth (%) (0.9) 0.9 (0.7) (7.22) 0.08 6.40 Average Rate (P/kWh) 2.42 2.68 3.12 3.75 3.46 4.57 Operating Revenue 89,686 100,119 115,698 116,433 119,179 167,276 (P million) Operating Expenditure 81,196 94,681 108,860 115,911 124,527 145,127 (P million) Operating Income 8,490 5,438 6,838 522 (5,349) 22,149 (P million) Net Income (P million) (5,952) (12,964) (10,337) (33,735) (117,989) (29,901) Rate Base 255,448 243,805 242,759 232,646 232,326 225,747 (P million) RORB (%) 3.32 2.23 2.82 0.22 (2.30) 9.81 DSCR 0.92 0.74 0.70 0.47 0.13 0.23 ( ) = negative, DSCR = debt service coverage ratio, GWh = gigawatt hour, kWh = kilowatt hour, NPC=National Power Corporation, P = Philippine peso, RORB = return-on-rate base. Source: Asian Development Bank estimates.

15. To address the problems facing the power sector, ADB is helping the Government restructure and privatize the electricity industry through Power Sector Assets and Liabilities Management Corporation (PSALM).5 The EPIRA, approved in June 2001, provided the blueprint for restructuring and privatizing the electric power industry. NPC’s generating assets were transferred to PSALM, which is charged with privatizing them. The transmission assets were assigned to Transco, a separate corporate entity that will contract the grid’s operation and maintenance to a private concessionaire through a 25-year agreement. Under the new arrangements, PSALM will be responsible for repaying all of ADB’s loans to NPC. The proceeds from the privatization and concession, along with a Government cash injection of as much as P200 billion, are to be used to cover NPC’s financial obligations.

16. In July 2005, ADB’s Board of Directors approved the Government’s request to transfer all liabilities and generation assets of NPC to PSALM, and all transmission and subtransmission assets to Transco. 6 ADB, NPC, PSALM, and Transco signed an omnibus amendment agreement in March 2006. Subject to meeting all of its conditions, this agreement amends previous ADB loan agreements with NPC. Given its projected revenue sources, PSALM should be able to meet at least a DSCR of 1.0 starting in 2009. The RORB covenant is not relevant to PSALM, because it will not have any asset operational functions. Transco has clear commercial functions, and its tariffs are regulated by the Energy Regulatory Commission (ERC) using performance-based rate-setting mechanism. As such, the RORB covenant is no longer applicable to Transco.

17. Based on its unaudited accounts, NPC earned a net income of P16 million in 2005, its first profit since 1997. NPC lost P117 billion in 2003 and P30 billion in 2004. This turnaround was largely attributed to (i) reduced interest expense following the Government’s absorption of P200 billion in debt; (ii) tariff increases granted by ERC; (iii) improvement in the

5 ADB. 1998. Report and Recommendation of the President to the Board of Directors on a Proposed Loan and Technical Assistance Grants to the Republic of the Philippines for the Power Sector Restructuring Program. Manila (Loan 1662-PHI, for $300 million, approved 16 December). 6 ADB. 2005. Report on the Transfer of Liabilities and Generation Assets from the National Power Corporation to the Power Sector Assets and Liabilities Management Corporation and Transfer of Transmission Assets from the National Power Corporation to the National Transmission Corporation in the Republic of The Philippines. Manila (approved on 19 July).

7 fuel mix, maximizing geothermal, hydroelectric, and other domestic energy sources; and (iv) foreign exchange gains resulting from the appreciation of the peso.

H. Consultant Recruitment and Procurement

18. ADB-financed supply contracts were procured through international competitive bidding, except the repair of the Leyte-Cebu submarine cables, which was procured through international shopping due to the urgency of the work. ADB and NPC disagreed on the procurement process for Part A. After project approval in December 1997, NPC asked ADB to approve a change in the design of the Leyte-Cebu interconnection to allow the construction of two cables instead of three cables, and the use of the existing spare cable to complete the electrical circuit. NPC indicated that the change was in line with the Government’s policy of adopting economy and efficiency in all public sector projects. ADB concurred with this request, recommending that NPC consider laying a spare cable eventually to achieve the most reliable system configuration. The bidding documents specified that two oil-filled submarine power cables will be required, while a third cable was listed as an option. NPC submitted its bid evaluation report in January 2001. In April 2001, ADB’s Procurement Committee approved NPC’s recommendation to award the contract to the lowest evaluated, substantially responsive bidder. However, in October 2001, the Government requested ADB’s concurrence to rebid the contract. The Government explained that the original bid was for two cables with an option for a third cable, which is not the same as a three-cable transmission line—the original project configuration approved by the Government’s Investment Coordination Committee (ICC). Without its prior approval, the Government indicated that NPC’s action was invalid and the bidding process for the two cables was legally groundless. From ADB’s perspective, however, the lapse in internal procedural compliance was not a basis for agreeing to a rebidding. Subsequently, the Government decided to source alternative financing for Part A, and requested cancellation of the corresponding loan allocation. ADB canceled the loan allocation for Part A on 9 August 2002.

19. In accordance with ADB’s Guidelines on the Use of Consultants, ADB approved advance action for the recruitment of consultants at the Management Review Meeting to meet the implementation schedule. NPC requested that only the consulting firm that performed the design and contract supervision work for the first interconnection circuit under World Bank financing be invited to submit a proposal. To justify this request, NPC advised that the (i) consultants had in-depth knowledge of the project design as they had designed the first circuit, which would be the basis of the second circuit design; (ii) consultants were aware of the working environment and matters that arose during construction of the first circuit as they had supervised the construction; and (iii) implementation schedule required the tender documentation to be ready by mid-1998, and direct selection would facilitate meeting this deadline. Satisfied with the performance of the consultant, NPC requested direct selection in the interests of economy and efficiency. ADB approved NPC’s request. The engineering design and construction supervision for the other project components were undertaken by NPC staff, which had adequate technical resources in this area.

I. Performance of Consultants, Contractors, and Suppliers

20. The performance of the suppliers and contractors was generally satisfactory. Implementation was delayed because Transco encountered a delay in obtaining the ROW needed to start civil works. The consultant was recruited to prepare the engineering design and supervise the construction of the Leyte-Cebu interconnection project. Although financing was canceled for the Leyte-Cebu interconnection project, the consultant produced high-quality output and ensured the successful completion of this component with alternative financing. The

8 consultant also provided additional services for the repair work of Leyte-Cebu interconnection. Overall, the consultant’s performance was satisfactory.

J. Performance of the Borrower and the Executing Agency

21. Progress reports were submitted periodically, and ADB was kept informed about the Project’s implementation progress. However, Transco did not form a multipartite monitoring team as envisaged at appraisal. The team was expected to comprise representatives from NPC, Department of Environment and Natural Resources (DENR), local government, nongovernment organizations, and PMO. Nevertheless, Transco maintained effective working relations with DENR, local governments, and nongovernment organizations during project implementation. Transco did not submit a report on the project’s environmental compliance, as required by ADB, and its progress report did not include a section on environmental compliance.

22. NPC and Transco’s procedures for the preparation and approval of contracts were complex, delaying implementation. NPC’s Board of Directors approved the contract award for procurement of Part A, and sent its recommendation to ADB. However, after ADB approved the award, the Government decided to rebid the contract as NPC failed to comply with internal project approval procedures. The decision to rebid was the main reason for the 5-year delay of the Leyte-Cebu interconnection uprating. In addition, the rebidding increased the project cost by about $10 million.

23. Transco complied with ADB guidance and national laws for land acquisition and resettlement. The valuation and compensation procedure involved an information campaign, data gathering and verification of documentary requirements (e.g., land titles, proof of ownership, tax declarations), cost valuation, negotiation, and processing of payment. Expropriation cases were filed in court for failed negotiations. Since 2,292 people were affected (para. 39), Transco was unable to complete the land acquisition and resettlement plan within the appraised implementation schedule. Acute ROW problems between Calamba and Biñan transmission lines required Transco to reroute the original line, which delayed the completion of the Batangas-Biñan transmission lines.

24. In light of these issues and significant delays in project implementation, the performance of NPC as Borrower and Transco as Executing Agency is considered unsatisfactory. However, Transco’s decision to upgrade the Dasmarinas-Biñan transmission lines, and its timely completion, enabled the dispatch of the generating capacity of the Ilijan, Sta. Rita, and San Lorenzo power plants, even though the completion of Batangas-Biñan transmission lines was delayed.

K. Performance of the Asian Development Bank

25. ADB adhered to its procurement guidelines when the Government disagreed with its position. Although its performance did not contribute to implementation delays, ADB’s contract approvals took longer than the time frames in the appraisal schedule. ADB review missions did not include a resettlement specialist, who could have assisted Transco in resolving land acquisition and ROW issues. ADB did not remind Transco to form an environmental monitoring team and submit an environmental compliance report, as envisaged at appraisal. ADB’s project administration was partly satisfactory.

III. EVALUATION OF PERFORMANCE

A. Relevance

26. The Project was in line with ADB’s operational strategy at appraisal. It continued to be relevant through its support for economic growth, an ADB priority for assistance to the Philippines.

B. Effectiveness in Achieving Outcome

27. The implementation delay of about 5 years did not disrupt the operation of the transmission system since the Project’s design was based on overly optimistic demand forecasts (para. 4). Overall, the Project is considered effective in meeting the electricity demand, and contributed to realizing the development goal as envisaged at appraisal.

C. Efficiency in Achievement of Outputs and Purpose

28. The completion of the Project increased the transmission capacity, enabling higher dispatch of the capacities for Sta. Rita, San Lorenzo, Quezon, Ilijan, and Calaca power plants (Table 4).

Table 4: Maximum Dispatch Capacity Power Plants Installed Capacity Maximum Dispatch Capacity, 2006 (MW) (MW) Sta. Rita 1,000 850 San Lorenzo 500 452 Quezon Power 440 385 Ilijan 1,200 1,100 Calaca 600 510 MW = megawatt. Source: National Transmission Corporation.

29. The economic and financial analysis of the Project is in Appendix 6. The financial and economic performance is reevaluated only for the ADB-financed Batangas transmission reinforcement component (part B).

30. The financial internal rate of return (FIRR) is computed based on (i) a project life of 25 years, (ii) transmission tariff of P0.53 per kilowatt hour (kWh), (iii) incremental operation and maintenance (O&M) costs of 2.5% of the capital costs of the transmission facilities, (iv) annual energy sales of 2,978 gigawatt-hour (GWh) and (v) transmission loss of 3%. Thus, the recalculated FIRR for the Batangas transmission reinforcement component is estimated at 17.4%. The sensitivity analysis showed that the FIRR would decrease to (i) 16.2% if electricity sales fell by 10%, (ii) 17.3% if its O&M costs increased by 10%, and (iii) 16.1% if sales fell by 10% and O&M costs increased by 10%. Under these assumptions, the Project is considered financially viable, because the FIRR exceeded the weighted average cost of capital.

31. The economic analysis is consistent with the financial analysis using the incremental benefits from the Project. The economic price of nontraded goods is equal to their domestic price. A shadow exchange rate factor of 1.2 (based on the standard conversion factor of 0.83) is applied to calculate the economic price of traded goods. The economic benefits from the incremental electricity sales are based on the average consumer willingness to pay at

P12.0/kWh. The willingness to pay is the average cost of alternative source of power, which includes diesel generators and kerosene-fired lamps for lighting among poorer consumers in rural areas. Other assumptions include (i) energy production costs of P7.1/kWh, (ii) transmission loss of 3%, and (iii) distribution loss of 15%. Thus, the Project’s recalculated economic internal rate of return (EIRR) for the 25-year project life is estimated at 38.5%. The EIRR calculation is subjected to a sensitivity analysis to test the effect of potential unfavorable changes in key variables. The sensitivity analysis is carried out for the following cases: (i) sales 10% lower than expected, (ii) energy costs 10% higher than estimated, and (iii) sales 10% lower than expected combined with costs 10% higher than expected. The results indicated that the Project is economically viable under all of the adverse conditions considered.

32. The completion of the Leyte-Cebu interconnection uprating increased the transfer capacity from 200 MW to 400 MW. However, the delay in completing this component significantly increased NPC’s generation costs in Cebu, as the required capacity had to be met with expensive diesel barges and dispatch of the old power plants. With the completion of the interconnection uprating, the dispatch level from geothermal plants in Leyte has increased by 160 MW, while the oil-fired plants in Cebu have been shut down. This has saved NPC about P200 million per month. Further, ADB-financed repair work for the existing Leyte-Cebu interconnection has produced positive economic and financial impacts. If the repairs had not been undertaken on a timely basis, a line failure could have caused significant harm to the industries, commercial establishments, and households in the region. Cebu would lose 200 MW of power supply from Leyte if one of the damaged cables failed. The generation reserve in Cebu is only about 50 MW. In financial terms, the estimated revenue loss to NPC for a 6-month outage is around P1.20 billion.

D. Preliminary Assessment of Sustainability

33. In general, Transco’s revenue is ensured through performance-based regulation. Therefore, the project outcomes are likely to be sustainable. For Part A, the Leyte-Cebu interconnection cables built by the Project are good quality. As such, they will be operational for about 40 years with regular maintenance, and strict compliance with safety and operational procedures. However, submarine cables are vulnerable to accidental damage, as demonstrated by the first circuit of the interconnection cables implemented with World Bank financing. Dynamite fishing damaged cables 3 and 4 of the first circuit in 1999. The scope of the ADB loan was changed to include the repair of these cables (para 5). To prevent recurrences of such damage, Transco embedded the cables at 30 meters water depth compared with the existing 10 meters. In addition, Transco has adopted strict security measures, employing 24-hour services of the Philippine National Police, fish warden, additional security guards, and continuing surveillance and patrol using NPC’s speed boat. Local governments also have provided support to sensitize the local communities.

34. For Part B (Batangas transmission reinforcement), sustainability can be ensured with good maintenance of the facilities, and strict compliance with safety and operational procedures. As part of Transco’s effort to ensure quality, consistency, and commitment to the highest standards of operations, eight of Transco’s major groups have passed the stringent International Standards Organization certification audits—System Operations (October 2003), Visayas O&M (December 2004), North Luzon O&M (April 2005), Project Management Group (June 2005), Administration Department-Head Office (July 2005), Engineering Design and Construction (August 2005), Mindanao O&M (August 2005), and South Luzon O&M (November 2005). Transco has assured that O&M of the completed transmission facilities are being financed by

11 internally generated cash. Maintenance standards of substation facilities visited during the PCR Mission were generally high.

E. Environmental, Sociocultural, and Other Impacts

1. Environmental Aspects

35. At appraisal, the Project was classified as environmental category B.7 Transco obtained environmental compliance certificates from DENR for the transmission lines and substations built under the Project. Transco used international standards and practices in the design and construction of project components. Polychlorinated biphenyl was not used in any transmission lines or substation equipment.

36. For Part A, the Leyte-Cebu power interconnection does not have a distinct reef structure on either side, as the corals are scattered due to the lack of a suitable substrate. The onshore facilities of the power interconnection were built within the existing terminals. For Part B, the transmission lines pass through gently rolling terrain. The soil in the area is loam with residuals of volcanic tuff. Soil erosion in the area is minimal. The area has been cultivated for a long time, and no endangered or threatened bird species are found. No scenic or tourism areas are found along the transmission ROW. Before project implementation, NPC conducted public awareness campaigns to allay fears and clarify issues relating to exposure to electromagnetic fields.

37. At completion, the Project’s environmental implications were reviewed and no significant environmental impacts were identified. Transco operates and maintains the facilities built under the Project in accordance with (i) the Philippines national environmental laws, regulations, and standards; (ii) applicable provincial and local regulations and standards concerning environmental protection, land use, and safety; (iii) ADB’s Environmental Guidelines for Selected Industrial and Power Development Projects;8 and (iv) the conditions and restrictions included in the environmental clearance certificates issued by DENR.

2. Social Aspects

38. Part A (uprating of Leyte-Cebu submarine cable) did not involve any land acquisition or resettlement. For the ADB-financed transmission components under Part B, ADB approved NPC’s resettlement plan for implementation. Land acquisition and resettlement delayed the implementation of Part B considerably. During implementation, Transco established a task force to negotiate with landowners, house owners, and tenants affected directly by the Project. Most of the ROW problems were resolved through negotiation. For landowners who refused to accept NPC’s proposal to enter and construct transmission lines, Transco filed expropriation proceedings in court, in accordance with the prevailing national laws, to avoid excessive delays in implementing projects with public interests. Nevertheless, project implementation was delayed due to the large number of affected people.

39. At the time of the PCR Mission, the cost for land acquisition, compensation, and resettlement for Part B of the Project was estimated at P191 million, of which P160 million has been paid. For the Damarinas-Biñan transmission line, which was built using ADB-financed materials, the cost for land acquisition, compensation, and resettlement was P209 million, of

7 Projects are categorized as “B” if they could have some adverse environmental impacts, but of lesser degree or significance than those for category “A” projects. An initial environmental examination is required to determine whether significant environmental impacts warranting an environmental impact assessment are likely. 8 ADB. 1993. Environmental Guidelines for Selected Industrial and Power Development Projects. Manila.

12 which P199 million has been paid. The higher land cost near Metro Manila and the higher residential density of the affected areas raised the cost of Dasmarinas-Biñan. The Project affected 2,292 households and owners. The affected persons did not include any indigenous people. The status of payment for land acquisition and resettlement at the time of the PCR Mission is in Table 5.

Table 5: Status of Payment for Land Acquisition and Resettlement (as of 30 April 2006) Transmission Lines Number of Affected Paid Remarks Households and Owners San Lorenzo-Batangas 494 396 106 expropriation cases filed; 28 paid. Batangas-Makban 620 516 6 expropriation cases filed; 5 paid. Makban-Calamba 280 238 17 expropriation cases filed; 12 paid. Calamba-Biñan 376 365 No expropriation cases filed. Dasmarinas-Biñan 522 475 35 expropriation cases filed; 7 paid. Total 2,292 1,990 163 expropriation cases filed; 52 paid. Source: National Transmission Corporation.

40. Electricity is an input to most economic processes. As such, it is an important ingredient of economic development, which is essential for poverty reduction. The Project has helped maintain acceptable levels of quality and reliability of the electricity supply in Luzon and Visayas. The impact of the Project on poverty reduction could not be quantified. However, the upgrading and expansion of the transmission system in Luzon and Visayas helped meet the additional power demand in these service areas and facilitate rural electrification, which benefit the poor directly and indirectly.

IV. OVERALL ASSESSMENT AND RECOMMENDATIONS

A. Overall Assessment

41. The Project was implemented with major changes in the financing plan for Part A and lengthy implementation delays. At the request of the Government, ADB canceled financing for Part A due to a disagreement over the procurement process. Nevertheless, Part A was completed using alternative financing. Difficulties in obtaining the necessary ROW for the transmission lines caused most of the implementation delays for Part B. However, overly optimistic demand growth forecasts mitigated the negative impacts of the delays in completing the Project. Overall, the Project is rated partly successful.

B. Lessons Learned

42. The major change in the financing arrangements for Part A delayed the completion of the Leyte-Cebu interconnection uprating by about 5 years. Closer consultation between ADB and NPC at each step of the procurement, particularly on the issue of project scope (para 18), could have avoided such a change and consequent delay.

43. The demand forecasts made at appraisal were overly optimistic, because the methodology used was based on the projected gross domestic product and constant elasticity coefficients. Such an econometric approach failed to capture the impact of the Asian financial crisis that slowed the country’s economic growth and suppressed electricity demand.

44. Before loan approval, ADB should have assessed thoroughly Transco’s capacity to deal with ROW issues. The project schedule at appraisal was unrealistic, because it did not take into

13 account the long time needed for Transco to comply with the procedures to secure an ROW. At the time of the PCR Mission, 302 affected households and owners (i.e., 13% of the total) had not received compensation (para 39). These issues led to long implementation delays for Part B. Transco could have mitigated many of the delays with forward planning and effective project management. ADB’s review mission could have included a resettlement specialist to advise and assist Transco in addressing ROW issues.

45. In accordance with the arrangements agreed at appraisal, ADB’s loan financed the supply and delivery of substation and transmission line equipment, while Transco financed the civil works and erection contracts. This arrangement required two procurement processes, and different contractors for the implementation of the same project components. Turnkey contracts could have reduced the implementation delays caused by the use of separate supply contracts (financed by ADB) and civil works and erection contracts.

C. Recommendations

46. The Project-related recommendations are:

(i) Covenants. Following the passage of EPIRA, NPC has been restructured and PSALM has taken over its liabilities. ADB should continue its policy dialogue with the Government, and closely review the financial viability of PSALM.

(ii) Project implementation schedules. The schedules should allow adequate time to secure necessary ROWs and ensure realistic time frames to evaluate bids and award contracts, in light of the procurement procedures for Transco and ADB.

(iii) Change of scope. ADB should review carefully the Borrower’s request for a change in scope, and verify if Government’s internal procedures have been complied with.

(iv) Inclusion of resettlement specialist in review missions. ADB review missions should include a resettlement specialist to monitor closely the implementation of land acquisition and the resettlement plan.

(v) Future monitoring and follow-up actions. ADB should continue to review and monitor the remaining residual work to ensure project completion by September 2006. Regular follow-up actions also are needed to monitor progress of payment to the remaining affected households.

47. General recommendations are:

(i) Demand forecasts. The demand forecasts using an econometric approach have been unreliable in the Philippine context. ADB should assess Transco’s demand forecasts using alternative methods.

(ii) Procurement method. To reduce delays in the implementation of transmission projects, turnkey contracting is preferable to separate supply contracts and erection contracts.

(iii) Financial covenants. The RORB covenant is no longer applicable to developing member countries that are introducing performance-based regulation for their public utilities. ADB should consider alternative financial covenants.

48. Additional Assistance. ADB’s country strategy and program 2005–2007 for the Philippines 9 emphasizes power sector reform as one of the key interventions for directly impacting the country’s three most critical development constraints: (i) fiscal imbalance, (ii) poor investment climate, and (iii) weak governance. In 2005, ADB’s Operations Evaluation Department prepared the Sector Assistance Program Evaluation 10 of ADB’s assistance to Philippines’ power sector. This evaluation concluded that this would be an inopportune time for ADB to cease support, because (i) sector reforms are at a critical transition phase, and (ii) the sector still needs a huge amount of liquidity to meet its financial obligations. Therefore, as the lead financing agency in the sector, ADB should continue to support the Government’s power sector restructuring program.

49. Timing of the Project Performance Audit Report. The project performance audit report is recommended for 2007, after commissioning of the transmission lines in Batangas.

9 ADB. 2005. Country Strategy and Program 2005–2007: Philippines. Manila. 10 ADB. 2005. Sector Assistance Program Evaluation of Asian Development Bank Assistance to Philippines Power Sector. Manila.

Appendix 1 15

PROJECT FRAMEWORK

Design Performance Assessment Summary Indicators/Targets Goal • Creation of a • Deliver adequate power at • The Project improved system competitive market affordable prices reliability and ensured adequate in electricity • Improve system stability power supply and rural generation and reliability, reduce electrification in Luzon and • Restructuring and system losses, and Visayas. However, electricity privatization of promote generation prices remain high as the power NPC expansion in an sector restructuring and creation • Support of private environmentally sound of competitive market are still in sector generation manner progress. expansion • Increase electrification • Reinforcement and ratio using indigenous expansion of resources transmission grids • Reduce the additional • Consolidation of capacity requirements distribution utilities • Utilization of renewable resources for rural electrification • Support for demand-side management and energy conservation Purpose • Expand and • Expand the carrying • The transfer capacity of Leyte- strengthen the capacity of the Leyte- Cebu interconnection has been transmission Cebu interconnection by expanded by 200 MW. system to support 200 MW to enable greater the envisaged use of Leyte-based IPP • Batangas transmission system will competitive market • Expand and reinforce the be reinforced to enable the in electricity Batangas transmission connection of an additional 1,760 generation to system to enable the MW of IPPs to the Luzon grid. facilitate economic connection of an growth additional 1,650 MW of IPPs to the Luzon grid Output • Laying of the • 32 km of submarine cable • Installed as designed. second circuit of (5) 230 kV PCB; (1) 138 the Leyte-Cebu kV PCB; (3) 50 MVAR interconnection reactors; (1) 30 MVAR reactors; (1) 230/138 kV transformer and 22.5 MVAR of 60 kV capacitors

16 Appendix 1

Design Performance Assessment Summary Indicators/Targets • 78 km of 230 kV transmission line and (43) 230 kV PCBs and accessories

• Reinforcement and • A minor change in scope was expansion of the approved to reroute Calamba- Batangas Biñan transmission line (18 km). transmission system

Inputs • Materials and • Turnkey and supply • $148.1 million of ADB loan equipment contracts totaling $166 canceled million • Consulting services • Consulting services of $1 million • Funds • Funding of interest during construction of $24 million

ADB = Asian Development Bank, IPP = independent power producer, km = kilometer, kV = kilovolt, MW = megawatt, MVAR = megavolt-ampere, NPC = National Power Corporation, PCB = power circuit breakers.

Appendix 2 17

CHRONOLOGY OF EVENTS

Project Processing

29 April–19 May 1997 – Fact-Finding Mission 11 August–4 September 1997 – Appraisal Missions 10–18 November 1997 – Loan Negotiations 16 December 1997 – Loan Approval 21 January 1998 – Loan Signing 3 April 1998 – Loan Effectiveness

Implementation

24 September 1998 – Effectiveness of consultancy services contract.

27 May 1999 – National Power Corporation (NPC) requests Asian Development Bank (ADB) to build only two cables, instead of three, and use the spare single core cable of the existing circuit to complete the circuit for the ADB-financed interconnection, in compliance with Government’s adoption of cost-cutting measures for all its projects.

3 August 1999 – ADB approves NPC’s request to build only two cables.

17 January 2001 – NPC submits bid evaluation report recommending Sumitomo Corporation for contract award.

22 January 2001 – Effectiveness of supply contract for transmission line materials—line hardware and accessories.

31 January 2001 – Effectiveness of supply contract for transmission line materials—composite optical ground wire.

10 April 2001 – ADB Procurement Committee approves awarding the contract to the lowest evaluated and responsive bidder for building two cables.

9 July 2001 – Effectiveness of supply contract for transmission line materials—steel tower structure, body, and leg extensions.

4 July 2001 – ADB approves partial loan cancellation of $70.32 million as a result of loan savings.

18 July 2001 – Effectiveness of supply contract for transmission line materials—power conductor, overhead ground wire, guy wire, and ground lead wire.

19 October 2001 – ADB is informed via a letter, dated 2 October 2001, from Secretary Camacho, Department of Finance, of the Government’s decision to rebid. The letter states that when NPC requested ADB approval to build two cables instead

18 Appendix 2

of three, it did not have the approval of the Government’s Investment Coordination Committee. Without prior approval from the Government, NPC’s action is considered invalid. Therefore, the National Economic and Development Authority Board chaired by President Arroyo decided to rebid.

20 November 2001 – ADB’s Procurement Committee rules that the Government’s request for rebidding is not acceptable. The committee decides that the lapse in the Government’s internal procedure is not an adequate basis for canceling the result of the procurement process, which was carried out through fair and transparent international competitive bidding.

29 October 2001 – Effectiveness of supply contract for the telecommunication and protection system and effectiveness of supply contract for transmission line materials—insulators and insulator assemblies.

12 December 2001 – Effectiveness of supply contract for substation equipment for Batangas and Biñan substations.

18 December 2001 – ADB approves first loan closing date extension from 30 June 2002 to 31 December 2003.

14 February 2002 – Effectiveness of supply contract for substation equipment for San Pascual and Sta. Rita power stations and Makban switchyard.

18 April 2002 – Transco requests the cancellation of $67 million earmarked for Leyte-Cebu interconnection uprating.

16 July 2002 – Effectiveness of turnkey contract for the repair of damaged subcables 3 and 4 of the Leyte-Cebu interconnection.

30 July 2002 – ADB approves fund reallocation ($8.30 million) for the additional cost of the rerouted Calamba tower 50—Biñan transmission lines.

9 August 2002 – ADB approves partial loan cancellation of $67.0 million due to the Government’s decision to rebid the Leyte-Cebu interconnection uprating component using alternative sources.

15 September 2002 – Repair of the damaged submarine cable 4 of the Leyte- Cebu interconnection completed.

2 October 2002 – Repair of the damaged submarine cable 3 of the Leyte- Cebu interconnection completed.

Appendix 2 19

8 December 2002 – Effectiveness of construction and erection contract for Makban-Calamba tower 50 transmission lines.

19 March 2003 – Issuance of certificate of final acceptance to Northeast China Electric Power Import and Export Corporation for the supply and delivery of transmission materials.

29 April 2003 – Issuance of certificate of provisional acceptance to Alstom T&D PTE, Ltd. for the supply and delivery of telecommunication and protection system.

12 May 2003 – Effectiveness of construction and erection contract for San Lorenzo-Batangas transmission lines.

19 June 2003 – Effectiveness of construction and erection contract for Batangas-Makban transmission lines.

15 October 2003 – Issuance of certificate of provisional acceptance to Harbin Power Engineering Co., Ltd. for the supply and delivery of San Pascual switchyard, Sta. Rita switchyard, and New Makban substation equipment.

16 October 2003 – Issuance of certificate of final acceptance to Mitsui and Co., Ltd. for the supply and delivery of transmission materials.

11 November 2003 – Issuance of certificate of final acceptance to China East Resources Import and Export Company for the supply and delivery of transmission materials.

24 November 2003 – Effectiveness of construction and installation contract for Batangas substations.

28 November 2003 – Issuance of certificate of final acceptance to KEC International Limited for the supply and delivery of transmission materials.

17 December 2003 – ADB approves the second loan closing date extension from 31 December 2003 to 31 December 2004.

26 January 2004 – Effectiveness of construction and installation contract for Makban A switchyard.

4 March 2004 – Issuance of certificate of provisional acceptance to Hyundai Corporation for the supply and delivery of Batangas and Biñan substation equipment.

2 August 2004 – ADB approves partial loan cancellation of $8.30 million due to the transfer of Calamba tower 50—Biñan transmission lines component to ADB loan 1984-PHI.

20 Appendix 2

6 August 2004 – Issuance of certificate of provisional acceptance to Alstom T&D PTE, Ltd. for the supply and delivery of substation equipment, telecommunication and protection system.

17 November 2004 – Effectiveness of construction and installation contract for Biñan substation.

10 January 2005 – Biñan-Dasmariñas 230-kilovolt transmission lines energized.

22 March 2005 – San Lorenzo-Batangas 230-kilovolt transmission lines energized.

1 April 2005 – Loan closing.

10–19 April 2006 – Project Completion Review Mission.

Appendix 3 21

ACTUAL DISBURSEMENTS ($ million)

Year Quarter Amounts Cumulative Annual

1998 2nd 0.02 0.02 3rd 0.00 0.02 4th 0.21 0.24 0.24

1999 1st 0.00 0.24 2nd 0.16 0.40 3rd 0.00 0.40 4th 0.33 0.73 0.50

2000 1st 0.00 0.73 2nd 0.41 1.14 3rd 0.05 1.14 4th 0.73 1.92 1.18

2001 1st 0.13 2.04 2nd 0.69 2.73 3rd 1.63 4.36 4th 4.96 9.32 7.41

2002 1st 5.07 14.39 2nd 3.79 18.17 3rd 6.05 24.23 4th 9.73 33.96 24.63

2003 1st 2.45 36.40 2nd 1.47 37.87 3rd 0.58 38.45 4th 1.44 39.89 5.94

2004 1st 0.75 40.65 2nd 1.19 41.84 3rd 0.31 42.15 4th 0.92 43.07 3.18

2005 1st 0.17 43.24 2nd 0.06 43.30 0.22

Source: Asian Development Bank.

22 Appendix 4

nal Transmission 2004 2005 2006 2002 2003 fourth quarter, Transco = Natio

ter, Q3 = third quarter, Q4 = 1998 1999 2000 2001 1997 Implementation Schedule (Appraisal vs Actual) Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 d National Transmission Corporation.

ssion Reinforcement Appraisal Actual ADB = Asian Development Bank,first quarter, Q2 = Q1 = second quar Corporation. Sources: Asian Development Bank an Right-of-WaySocial (ADB/TRANSCOBidding financing) - Calaca Rita Sta - Dasmariñas Calaca Lorenzo San - Batangas Batangas - Biñan -Dasmariñas Biñan Activities Interconnection Leyte-Cebu A. Uprating Bidding Implementation Repair of SubmarineLeyte-Cebu Cables B. Batangas Transmi

Appendix 5 23

STATUS OF COMPLIANCE WITH LOAN COVENANTS

Reference in Loan Covenant Agreement Status of Compliance

Plans, Design Standards, Specifications, and Work Schedules

NPC, in consultation with the Government, will Schedule 6, Complied with. develop a plan for the future of the Manila and para. 12 (i) Sucat power plants (Manila and Sucat power plants plan).

NPC, in consultation with the Government, will Schedule 6, Complied with. develop a policy for the use of natural gas para. 12 (ii) (natural gas policy).

NPC will develop a financial model simulating Schedule 6, Complied with. the effect on overall corporate profitability of para. 10 (ii) various privatization options.

Reports and Information

NPC shall provide ADB with reports concerning Schedule 6, Complied with. its restructuring and privatization program on a para. 10 (i) quarterly basis.

NPC shall furnish to ADB quarterly reports on Article IV, Complied with. the execution of the Project. Section 4.06 (b)

Within 3 months of physical project’s completion, Article IV, Complied with. NPC will prepare a PCR and forward it to ADB. Section 4.06 (c)

Audited Financial Statements

NPC shall furnish to ADB certified copies of its Article IV, Late compliance. audited financial statements within 6 months of Section 4.07 the end of each fiscal year.

Environmental and Social Matters

The Borrower shall design and implement the Schedule 6, Complied with. project components implemented by it, and para. 6 operate and maintain the project facilities, in accordance with (i) the Guarantor’s national environmental laws, regulations, and standards; (ii) all applicable provincial and local regulations and standards concerning environmental

24 Appendix 5

Reference in Loan Covenant Agreement Status of Compliance protection, land use, and safety; (iii) ADB’s Environmental Guidelines for Selected Industrial and Power Development Projects; and (iv) the conditions and restrictions included in environmental clearance certificates issued by the Environmental Management Bureau within DENR.

NPC will ensure that any relocation and Schedule 6, Ongoing. compensation of households affected by Parts para. 4 B1 to B4 of the Project are carried out in accordance with the resettlement plan, and in a timely manner.

The Batangas-Biñan transmission line, Schedule 6, Ongoing. the new 67 kV transmission line to be para. 2 constructed from Batangas to Biñan under Part B (iii) of the Project, shall be built on the Borrower’s existing right-of-way. New transmission tower foundations shall first be built between the existing tower foundations. Upon completion of the new foundations, the Borrower shall dismantle the existing transmission line, erect new transmission towers on the new foundations, and install transmission line.

The Borrower shall ensure that the new Schedule 6, Ongoing. transmission towers and transmission tower para. 3 foundations are sufficiently high to provide the required clearance over the residences and structures that exist along the Borrower’s right- of-way. The Borrower also shall take all necessary measures to protect such residences and structures from damage while work on the transmission line is taking place, including but not limited to using scaffolding of sufficient strength and stability.

Tariffs

NPC shall implement a suitable tariff increase Schedule 6, Not complied with. required to ensure a 7% RORB in 1998. para. 7 (i)

NPC shall earn an annual RORB of at least 8% Schedule 6, Not complied with. from 1999 onward. para. 7 (ii)

Appendix 5 25

Reference in Loan Covenant Agreement Status of Compliance NPC shall maintain a debt service coverage Schedule 6, Not complied with. ratio of at least 1.0 times until 1999, and 1.3 para. 7 (iii) times thereafter.

ADB = Asian Development Bank, DENR = Department of Environment and Natural Resources, kV = kilovolt, NPC = National Power Corporation, PCR = project completion report, RORB = rate on return base.

26 Appendix 6

FINANCIAL AND ECONOMIC ANALYSIS OF THE PROJECT

A. General

1. The financial and economic performance is reevaluated only for the Batangas transmission reinforcement component (Part B) of Power Transmission Reinforcement Project. At the request of the Government of the Philippines, the Asian Development Bank (ADB) canceled the Leyte-Cebu interconnection uprating component (Part A, for $112 million), and financed $14 million for repairs to the damaged Leyte-Cebu interconnection submarine cables.

2. The report and recommendation of the President assumed that the Project would enable the transmission of power from the 300 megawatt (MW) San Pascual power plant to the main load centers around Metro Manila. However, the San Pascual plant was replaced by the 500 MW gas-fired San Lorenzo power plant to utilize natural gas from the Malampaya field. Therefore, this financial and economic analysis is based on the assumption that the Project would enable the transmission of electricity generated from San Lorenzo power plant to the main load centers.

3. Due to procurement delays for the Calamba-Biñan transmission line, the full benefit of Batangas-Makban-Biñan 230 kilovolt (kV) transmission line can be achieved only by June 2008. Therefore, the additional investment costs for Calamba-Biñan line are included in the total investment costs for the calculation of financial and economic costs. The capital costs for the financial and economic analysis are recalculated in 2006 prices. The capital costs are converted from US dollars to Philippine pesos ($1 = P52).

B. Financial Evaluation

4. As a proxy for the financial opportunity cost of capital, the weighted average cost of capital for the Project is calculated at 4.7% (Table A6.1).

5. A financial internal rate of return (FIRR) is computed based on (i) a project life of 25 years, (ii) transmission tariff at P0.53 per kilowatt hour (kWh), (iii) incremental operation and maintenance (O&M) costs of 2.5% of the capital costs of the transmission facilities, (iv) annual energy sales of 2,978 gigawatt-hour (GWh), and (v) transmission loss of 3%. The additional cost for the Calamba-Biñan transmission line is included in the project costs.

6. The FIRR for the Batangas transmission reinforcement component is estimated at 17.4% (Table A6.2). The sensitivity analysis shows that the FIRR would decrease to (i) 16.2% if electricity sales fell by 10%, (ii) 17.3% if its O&M costs increased by 10%, (iii) 16.1% if sales fell by 10% and O&M costs rose by 10%. Under the current assumptions, the Project is considered financially viable, because the FIRR exceeds the weighted average cost of capital.

C. Economic Evaluation

7. The economic analysis is consistent with the financial analysis using the incremental benefit from San Lorenzo power plant. The economic prices of nontraded goods are equal to their domestic prices. A shadow exchange rate factor of 1.2 (based on the standard conversion factor of 0.83) is applied to calculate the economic price of traded goods. The economic benefits from the incremental electricity sales are based on average consumer willingness to pay at P12.0/kWh. The willingness to pay is the average cost of alternative source of power, which includes diesel generators and kerosene-fired lamps for lighting among poorer consumers in

Appendix 6 27 rural areas. Other assumptions include (i) energy production costs of P7.1/kWh, (ii) transmission loss of 3%, and (iii) distribution loss of 15%.

8. The Project’s economic internal rate of return (EIRR), calculated for the 25-year project life, is estimated at 38.5% (Table A6.3). The EIRR calculation is subjected to sensitivity analysis to test the effect of potential unfavorable changes in key variables. The sensitivity analysis is carried out for the following cases: (i) sales 10% lower than expected; (ii) energy costs 10% higher than estimated; and (iii) a combination of 10% lower sales and 10% higher costs. The results indicate that the Project is economically viable under all of the adverse conditions considered.

Table A6.1: Weighted Average Cost of Capital Calculation

Financing Component Government ADB Loan Total Funds A. Amount ($ million) 43.3 25.6 68.9 B. Weighting (%) 62.8 37.2 100.0 C. Nominal Cost of Funds (%) 6.1 12.0 D. Tax rate (%) 0.0 0.0 E. Tax-adjusted Nominal Cost (%) 6.1 12.0 F. Inflation Rate (%) 1.9 6.0 G. Real Cost (%) 4.1 5.7 H. Weighted Component of WACC (%) 2.6 2.1 4.7

Weighted Average Cost of Capital (%) 4.7

ADB = Asian Development Bank, WACC = weighted average cost of capital. Source: Asian Development Bank estimates.

28 Appendix 6

Table A6.2: Financial Internal Rate of Return (Peso million)

Year Costs Benefits Net Capital Q&M Total Costs Incremental Incremental Financial Costs Costs Energy Sales Sales Benefits (GWh) 1998 5.5 5.5 (5.5) 1999 32.6 32.6 (32.6) 2000 61.5 61.5 (61.5) 2001 385.2 385.2 (385.2) 2002 1,572.3 1,572.3 (1,572.3) 2003 548.2 548.2 (548.2) 2004 537.6 537.6 (537.6) 2005 139.5 139.5 (139.5) 2006 289.2 289.2 (289.2) 2007 412.3 412.3 (412.3) 2008 99.6 99.6 1,488.9 787.3 687.7 2009 99.6 99.6 2,977.9 1,574.7 1,475.1 2010 99.6 99.6 2,977.9 1,574.7 1,475.1 2011 99.6 99.6 2,977.9 1,574.7 1,475.1 2012 99.6 99.6 2,977.9 1,574.7 1,475.1 2013 99.6 99.6 2,977.9 1,574.7 1,475.1 2014 99.6 99.6 2,977.9 1,574.7 1,475.1 2015 99.6 99.6 2,977.9 1,574.7 1,475.1 2016 99.6 99.6 2,977.9 1,574.7 1,475.1 2017 99.6 99.6 2,977.9 1,574.7 1,475.1 2018 99.6 99.6 2,977.9 1,574.7 1,475.1 2019 99.6 99.6 2,977.9 1,574.7 1,475.1 2020 99.6 99.6 2,977.9 1,574.7 1,475.1 2021 99.6 99.6 2,977.9 1,574.7 1,475.1 2022 99.6 99.6 2,977.9 1,574.7 1,475.1 2023 99.6 99.6 2,977.9 1,574.7 1,475.1 2024 99.6 99.6 2,977.9 1,574.7 1,475.1 2025 99.6 99.6 2,977.9 1,574.7 1,475.1 2026 99.6 99.6 2,977.9 1,574.7 1,475.1 2027 99.6 99.6 2,977.9 1,574.7 1,475.1 2028 99.6 99.6 2,977.9 1,574.7 1,475.1 2029 99.6 99.6 2,977.9 1,574.7 1,475.1 2030 99.6 99.6 2,977.9 1,574.7 1,475.1 2031 99.6 99.6 2,977.9 1,574.7 1,475.1 2032 99.6 99.6 2,977.9 1,574.7 1,475.1 2033 99.6 99.6 2,977.9 1,574.7 1,475.1 FIRR = financial internal rate of return, GWh = gigawatt-hour, NPV = net present value, O&M = operation and maintenance, WACC = weighted average cost of capital, Source: Asian Development Bank estimates. NPV 10,347 FIRR (%) 17.4 WACC (%) 4.7

Sensitivity Analysis (%) Base Case 17.4 10% Sales decrease 16.2 10% O&M increase 17.3 All risks 16.1

Appendix 6 29

Table A6.3: Economic Internal Rate of Return

Year Cost Benefit Net Capital Q&M Energy Total Net Total Benefit Economic Costs Costs Costs Costs Energy Benefit (GWh) 1998 6.6 6.6 (6.6) 1999 39.1 39.1 (39.1) 2000 73.8 73.8 (73.8) 2001 462.2 462.2 (462.2) 2002 1,829.5 1,829.5 (1,829.5) 2003 609.0 609.0 (609.0) 2004 570.7 570.7 (570.7) 2005 141.8 141.8 (141.8) 2006 300.6 300.6 (300.6) 2007 472.6 472.6 (472.6) 2008 112.6 10,913.3 11,026.0 1,265.6 15,187.2 4,161.3 2009 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2010 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2011 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2012 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2013 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2014 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2015 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2016 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2017 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2018 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2019 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2020 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2021 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2022 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2023 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2024 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2025 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2026 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2027 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2028 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2029 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2030 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2031 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2032 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 2033 112.6 21,826.6 21,939.3 2,531.2 30,374.5 8,435.2 EIRR = economic internal rate of return, GWh = gigawatt-hour, NPV = net present value, O&M = operation and maintenance. Source: Asian Development Bank estimates.

NPV 10,630 EIRR (%) 38.5

Sensitivity Analysis (%) Base Case 38.5 10% Sales decrease 31.8 10% Energy cost increase 33.9 All risks 24.8