ASIAN DEVELOPMENT BANK PPA: PHI 24212

PROJECT PERFORMANCE AUDIT REPORT

ON THE

SIXTEENTH POWER (MASINLOC THERMAL POWER) PROJECT (Loan 1042-PHI)

IN THE PHILIPPINES

October 2002

CURRENCY EQUIVALENTS Currency Unit – Peso (P)

At Appraisal

(as of October 1990) At Project Completion

(as of January 1999) At Operations Evaluation

(as of May 2002)

P1.00 = $0.0388 = $0.0250 = $0.0202 $1.00 = P25.78 = P40.00 = P49.47

ABBREVIATIONS ADB – Asian Development Bank CEMS – continuous emissions monitoring system DENR – Department of Environment and Natural Resources ECC – environmental compliance certificate EIRR – economic internal rate of return ESP – electrostatic precipitator EIS – environmental impact study FBC – fluidized bed combustion FIRR – financial internal rate of return IPP – independent power producer LGU – local government unit MCDO – Municipal Cooperative Development Office MTPP – Masinloc Thermal Power Plant NGO – nongovernment organization NOx – nitrogen oxide NPC – National Power Corporation OEM – Operations Evaluation Mission O&M – operation and maintenance PAF – project-affected family PCR – project completion report PMO – project management office PPA – power purchasing agreement PPAR – project performance audit report SED – Social Engineering Department SO2 – sulfur dioxide TA – technical assistance UF – under frequency WTP – willingness-to-pay

NOTES

(i) The fiscal year (FY) of the Government ends on 31 December. (ii) In this report, “$” refers to US dollars.

Operations Evaluation Department, PE-605

WEIGHTS AND MEASURE

GWh (gigawatt-hour) – 1,000,000 kWh Hz (hertz) – unit of frequency equal to per second km (kilometer) – 1,000 meters kV (kilovolt) – 1,000 volts kWh (kilowatt-hour) – 1,000 watt-hours m (meter) – unit of length (metric) MVA (megavolt-ampere) – 1,000,000 volt-amperes MW (megawatt) – 1,000,000 watts MWh (megawatt-hour) – 1,000 kWh

CONTENTS

Page

BASIC DATA iii EXECUTIVE SUMMARY iv MAP vii I. BACKGROUND 1

A. Rationale 1 B. Formulation 1 C. Purpose and Outputs 2 D. Cost, Financing, and Executing Arrangements 2 E. Completion and Self-Evaluation 3 F. Operations Evaluation 3

II. PLANNING AND IMPLEMENTATION PERFORMANCE 4

A. Formulation and Design 4 B. Achievement of Outputs 5 C. Cost and Scheduling 6 D. Procurement and Construction 7 E. Organization and Management 8

III. ACHIEVEMENT OF PROJECT PURPOSE 8

A. Operational Performance 8 B. Performance of the Operating Entity 9 C. Financial and Economic Reevaluation 10

D. Sustainability 11 IV. ACHIEVEMENT OF OTHER DEVELOPMENT IMPACTS 11

A. Socioeconomic Impact 11 B. Environmental Impact 12 C. Impacts on Institution and Policy 13

V. OVERALL ASSESSMENT 14

A. Relevance 14 B. Efficacy 14 C. Efficiency 14 D. Sustainability 14 E. Institutional Development and Other Impacts 15 F. Overall Project Rating 15 G. Assessment of Asian Development Bank and Borrower Performance 15

VI. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS 16

A. Key Issues for the Future 16 B. Lessons Identified 16 C. Follow-Up Actions 17

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APPENDIXES 1. Project Cost and Financing Plan 19 2. Project Schedule 20 3. Generation Output Data for Masinloc Thermal Power Plant 21 4. Unit Outage/Availability for Masinloc Thermal Power Plant 23 5. Compliance with Major Loan Covenants 24 6. Reevaluation of Financial and Economic 25 Internal Rates of Return 7. Resettlement and Social Impact Evaluation 31 8. Environmental Monitoring Results 39 9. Organization Chart: National Power Corporation 41

BASIC DATA

PROJECT PREPARATION/INSTITUTION BUILDING TA No. Name Type Person-

Months Amount

($) Approval

Date 1405 Environmental Management of Coal-

Based Power Generation ADTA 50 636,000 30 Oct 1990

KEY PROJECT DATA ($ million) As per ADB Loan

Documents Actual

Total Project Cost 441.0 429.3Foreign Exchange Cost 350.0 393.5ADB Loan Amount/Utilization 200.0 196.8ADB Loan Amount/Cancellation 3.2Amount of Cofinancing 150.0 149.0 KEY DATES Expected Actual Fact-Finding 12–23 Mar 1990 Appraisal 30 May–15 Jun 1990 Loan Negotiations 18 Jul 1990 25–26 Sep 1990 Board Approval 15 Aug 1990 30 Oct 1990 Loan Agreement 19 Apr 1991 Loan Effectiveness 18 Jul 1991 23 Dec 1994 First Disbursement 28 Dec 1994 Project Completion 1 Oct 1994 18 Jun 1998 Loan Closing 30 Jun 1995 7 Jan 1999 Months (effectiveness to completion) 38 42 ECONOMIC AND FINANCIAL RATES OF RETURN (%) Appraisal PCR PPAR Economic Internal Rate of Return 14.5 28.8 29.7 Financial Internal Rate of Return 14.9 17.2 21.4 BORROWER National Power Corporation GUARANTOR Republic of the Philippines EXECUTING AGENCY National Power Corporation MISSION DATA No. of Missions No. of Person-Days Fact-Finding 1 58 Appraisal 1 107 Project Administration

Review 6 57 Project Completion 1 6 Operations Evaluation1 1 9

ADTA = advisory technical assistance, PCR = project completion report, PPAR = project performance audit report. 1 The Mission comprised C.C. Yu, Evaluation Specialist (Mission Leader); R. Rinker, Evaluation Specialist; W.M. Lewis,

Power Engineer (international consultant); and A. Corpuz, Resettlement and Social Impact Specialist (domestic consultant).

EXECUTIVE SUMMARY

In 1987, the resumption of economic growth in the Philippines caused power shortages in the main grids. In Luzon, such shortages reached severe levels in 1989 and the first half of 1990. The Asian Development Bank's (ADB) operational strategy in the power sector in the Philippines in the late 1980s focused on augmenting of power-generating capacity (including restoring the capacity of existing power stations) to meet the growing demand for power for economic development and to facilitate poverty reduction. The Project aimed to increase the base-load generating capacity of the Luzon grid to meet efficiently and economically the projected capacity and energy requirements, and to assist the Government in its efforts to diversify the country’s energy sources and reduce oil dependency. The Project was to cover Stage I of the Masinloc Thermal Power Scheme, and was to include the boiler and turbo-generator for the first 300-megawatt unit and associated coal and ash handling equipment, harbor facilities for unloading seaborne coal, cooling water and fresh water systems, powerhouse, and stack common to both the first and second units (the second unit with identical design was financed under a separate ADB loan). The Project was designed to use imported high-quality bituminous coal. A technical assistance grant was attached to the Project to help improve capacity of the National Power Corporation (NPC), the Executing Agency, in environmental monitoring and management. On 30 October 1990, the ADB Board approved a loan of $200.0 million for the Project. The total project cost was estimated at $441.0 million equivalent, including $350.0 million foreign exchange and $91.0 million local currency equivalent. The foreign exchange cost was to be jointly financed by ADB ($200.0 million), Export-Import Bank of Japan ($120.0 million), and NPC ($30.0 million); while the local currency cost was to be financed by NPC ($61.0 million equivalent) and Export-Import Bank of Japan ($30.0 million equivalent). Due to a series of unforeseen events related to land acquisition, resettlement, and obtaining the environmental compliance certificate (ECC), the ADB loan did not become effective until 23 December 1994. The Operations Evaluation Mission (OEM), which held discussions in Manila and visited Masinloc Thermal Power Plant (MTPP) during 20–31 May 2002, confirmed that all project components were implemented as envisaged at appraisal. Although not a direct part of the Project, the originally planned 230-kilovolt transmission lines from MTPP to the Hermosa substation in Bataan was rerouted to the Labrador substation in Pangasinan because of the eruption of Mt. Pinatubo in 1991. Despite the initial delay of about 3.5 years due to environmental and social concerns, the execution of the Project under a turnkey contract was efficient and within the budget and revised time schedule. Considering the initial delay, it is likely that compared with multicontract packaging, the turnkey approach resulted in cost savings and reduced the construction period, perhaps by as much as a year. Generally, the OEM found MTPP’s design and equipment to be least-cost, in conformance with the environmental standards, and of high quality. The total project cost amounted to $429.3 million equivalent, 3% below the appraisal estimate. However, there was a cost overrun on foreign exchange costs—the actual cost was $393.5 million compared with the appraisal estimate of $350.0 million—because the civil works contract was awarded to a foreign subcontractor. ADB financing amounted to $196.8 million, and the balance of $3.2 million was cancelled. After one extension, the loan was closed on 7 January 1999, about 3.5 years after the scheduled loan closing date. The OEM regards MTPP’s operation and maintenance to date as satisfactory. The upkeep appears to be according to generally accepted utility practice. Since their commissioning in June and December 1998, the two units have been used to meet part of the

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base load in the Luzon grid. During the initial operating period, their output suffered from transmission constraints and equipment outages. However, in 2001 and the first four months of 2002, the plant factor has exceeded 70% and availability 80% for both units, despite the generation capacity surplus in Luzon due to a large number of independent power producers (IPPs). This was attributable to MTPP’s relatively low generation costs and the fact that, from the viewpoint of system stability, there are some problems in using the large 600 megawatt units at the IPP plant in Sual for meeting base load in the relatively small grid in Luzon. Overall, MTPP has been providing stable and economical power supply for Luzon, and has helped improve conditions for economic development and investments amid the current public debate on the role of IPPs in power supply in the Philippines. Coal-fired power generation projects generally have major environmental impacts in the form of air emissions, discharge of cooling water and wastewater, and ash handling. Environment protection has been well incorporated in the design of the Project, including the exclusive use of low-sulfur coal for control of sulfur dioxide emissions, combustion at minimal excess air to limit nitrogen oxides emissions, a stack height of 150 meters, electrostatic precipitators removing particulate matter with an efficiency of 99.5%, limitations on the cooling water discharge temperature, emission monitoring, reforestation, and various measures in coal handling to limit dust dispersion. The design conforms to the ECC granted by the Department of Environment and Natural Resources (DENR). The ECC, several memorandums of agreement signed between NPC, the local government unit and DENR, and ADB loan covenants also require MTPP operators to implement various forms of emission control and monitoring. The OEM confirmed that NPC had established an environmental analysis laboratory and maintained a competent full-time environmental personnel. These personnel perform monitoring, maintain records of such, analyze samples, and interface with a multipartite committee consisting of NPC, the local government unit, the Department of Energy, DENR, and nongovernment organization representatives who perform joint quarterly sampling exercises with MTPP. The monitoring results indicate that the environmental emissions and discharges are well within DENR standards. The Project has had moderate socioeconomic impacts. During its implementation, NPC developed and implemented a resettlement program for 198 project-affected families (PAFs) living at the project site, in collaboration with the municipality of Masinloc. The resettlement program consisted of three compensation options and two livelihood programs. In-depth interviews carried out with 51 PAFs indicate that the resettlement program has largely achieved its main objective to relocate the PAFs within the boundaries of the project site after they had been compensated. Although on the whole the resettlement program was fair and socially and economically acceptable to PAFs, there are some problems and unresolved issues, including lack of drinking water on the resettlement sites, limited job opportunities and reduced income for some PAFs, delayed transfer of land ownership to the PAFs, and disputes over compensation amounts. On the other hand, the Project has contributed significantly to the betterment of conditions for economic development by providing reliable and economical power, which meets the demand not only of industrial and commercial customers in Metro Manila, but also an increasing number of newly connected rural households in northern Luzon. Over the years, NPC has been supporting local community development by building schools and roads in northern Luzon. The associated advisory technical assistance has achieved its main purpose of improving NPC’s environmental monitoring and management capacity.

The Project has been relevant in addressing the country’s power needs and consistent with ADB’s operational strategy in the power sector. The Project has achieved its purpose of efficiently and economically meeting the capacity and energy requirements in Luzon, and, thus, is efficacious. The Project has been a least-cost option for electricity generation in Luzon.

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Despite the initial delay of about 3.5 years, the execution of the Project under a single turnkey contract was efficient, and was within the budget and the revised time schedule. With the high financial and economic internal rates of return of 21.4% and 29.7%, respectively (notwithstanding the major delay), the Project is efficient. MTPP’s maintenance is generally satisfactory. The Project has had moderate impacts on institutional development and environment, and is likely to be sustainable. Overall, the Project is rated successful.

Several key issues affect the performance of the Project and/or the sector in general, including the tedious procedures for procuring spare parts at NPC, its future privatization, and the current debate over the role of IPPs. How these issues are resolved will have a significant impact on the Project’s long-term operational performance and sustainability. The key lessons derived from the Project include (i) avoiding front-end delays by gaining public acceptance, acquiring necessary land and rights-of-way, and preparing a comprehensive resettlement program before loan approval; and (ii) using the turnkey approach to ensure smooth implementation of this type of projects.

A series of follow-up actions are recommended. ADB should continue to provide assistance in the power sector in the Philippines, particularly for sector restructuring and development of a competitive electricity market. Without further delay, the Government should bring on track the much-anticipated privatization of NPC. It is also important that the Government approve a much-needed policy for involuntary resettlement. Several issues related to environmental monitoring and management, equipment operation, and timely procurement of coal and spare parts may potentially affect the long-term sustainability and performance of MTPP. These issues should be handled with urgency and in a forward-looking manner. In addition, several outstanding issues regarding resettlement require immediate attention of and resolution by NPC: the ongoing lawsuit against it on compensation filed by a group of resettlers, providing PAFs with drinking water by constructing water lines, studying the feasibility of providing more assistance to the local economy by constructing a basic market in a nearby area, and immediate transfer of land titles to the resettlers. These recommendations should be implemented before NPC’s privatization scheduled in the second half of 2003.

Map

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I. BACKGROUND A. Rationale 1. As a result of high oil prices and the serious economic difficulties that the Philippines experienced, commercial energy consumption as well as gross domestic product stagnated during 1980–1986. In 1987, however, a trend of increasing energy consumption started, and commercial energy consumption almost reached the 1979 peak of 12.4 million tons of oil equivalent. The share of oil in the commercial energy mix decreased from 94% in 1975 to 72% in 1989. The balance of the energy demand was met by hydropower, geothermal steam, and coal. The main thrust of the Government’s energy policy was to increase self-sufficiency and to lessen the impact of external factors on the economy. Therefore, the sector strategy mostly aimed at developing indigenous energy resources, diversifying energy sources, and reducing consumption through energy conservation and demand management. In addition, the Government made serious efforts to foster private sector participation, particularly in power generation. 2. Resumption of economic growth from 1987 led to power shortages in the main grids. In Luzon, such shortages reached severe levels starting in 1989 due to a combination of factors including the mothballing of a just completed nuclear power plant for safety reasons, drought that curtailed hydropower availability, and increased forced outages of the aging oil-fired generating facilities. Operational strategy of the Asian Development Bank (ADB) for the Philippines at the time gave priority to supporting poverty reduction and employment generation, especially in rural areas, and addressing the severe regional income disparities. For the power sector, one of the main objectives was to augment power generating capacity (including restoring capacity of existing power stations) to meet the growing demand for power for economic development and to assist the Government in its efforts to diversify the country’s energy sources and reduce oil dependency. The objectives also included enhancing operating efficiency as well as the use of indigenous energy resources. B. Formulation 3. The Project was formulated as ADB’s sixteenth lending operation in the Philippine power sector. During fact-finding in March 1990, the scope of the Project as well as the implementation and financing arrangements were discussed with the Government and the National Power Corporation (NPC), the principal power generation and transmission utility in the Philippines. It was confirmed that the Government accorded high priority to the Project and it was suitable for ADB financing. During appraisal in May/June 1990, detailed specifications of the Project were worked out with the Government and NPC using existing data and studies, including a site-selection and feasibility study undertaken by NPC in 1989 for establishing a 2 x 300 megawatt (MW) coal-based thermal power plant in Luzon. The ADB loan for the first 300 MW unit and all auxiliary equipment was approved in October 1990.1 However, due to a series of unforeseen events (para. 8), the loan did not become effective until December 1994.

1 Loan 1042-PHI: Sixteenth Power (Masinloc Thermal Power) Project, for $200 million, approved on 30 October

1990.

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C. Purpose and Outputs 4. The Project aimed to increase the base-load generating capacity of the Luzon grid to meet efficiently and economically the projected power requirements, and to diversify the country’s energy sources and reduce oil dependency. The Project was to cover Stage I of the Masinloc Thermal Power Plant (MTPP), and was to include the boiler and turbo-generator for the first 300 MW unit and associated coal and ash handling equipment, harbor facilities for unloading seaborne coal, cooling water and freshwater systems, powerhouse, and stack, which were common to both units. The Project was designed to use imported high-quality bituminous coal.2 The Project’s output was to be brought into the Luzon grid through a 130-kilometer (km), 230-kilovolt (kV), double-circuit transmission line from Masinloc to the Hermosa substation in Bataan via Botolan. The transmission line, which was to be financed, along with the second 300 MW unit under a separate ADB loan,3 was to be completed well before the first 300 MW unit was commissioned. 5. A technical assistance (TA) grant4 was attached to the Project to help NPC in (i) establishing a baseline air quality monitoring program for the Project; (ii) assessing the impacts of the cooling water discharge from the Project on coral reefs and fisheries in Oyon Bay; and (iii) examining the feasibility of using fly ash for commercial applications; (iv) providing equipment, software, and training to upgrade the capabilities of NPC’s environment management department; and (v) studying the feasibility of conversion to coal of oil-fired thermal power plants by using the fluidized bed combustion (FBC) technology, which would offer significant environmental benefits and would also be less sensitive to variations in coal quality. D. Cost, Financing, and Executing Arrangements 6. Appendix 1 gives a cost breakdown by project component and the proposed financing plan. At appraisal, the total project cost was estimated at $441.0 million equivalent, including $350.0 million foreign exchange cost and $91.0 million equivalent local currency cost. The foreign exchange cost was to be jointly financed by ADB ($200.0 million), Export-Import Bank of Japan ($120.0 million), and NPC ($30.0 million); while the local cost was to be financed by NPC ($61.0 million equivalent) and Export-Import Bank of Japan ($30.0 million equivalent). 7. NPC was the Executing Agency for the Project. A project management office (PMO) was to be established by NPC, and headed by a project director with appropriate qualifications and experience. The core staff of PMO were to be supported by additional qualified staff including project accounting staff at the later stage of project implementation. Partly because of the constraints on NPC’s project implementation capacities, NPC decided to adopt the turnkey approach for the Project, as opposed to multicontract packaging.5

2 The decision was to use imported coal because domestic coal could not meet the demand in a reliable and

economical manner, and had very high ash content and low heat value. 3 Loan 1398-PHI: Northern Luzon Transmission and Generation Project, for $244 million, approved on 2 November

1995. 4 TA 1405-PHI: Environmental Management of Coal-Based Power Generation, for $636,000, approved on 30

October 1990. 5 The other considerations for adopting the turnkey approach were its potential savings in time and costs. It was

thought that adopting a single turnkey contract could reduce the time of construction by up to 1 year, and any possible increase in project costs due to the turnkey contract could be more than offset by cost savings in fuels by switching from the alternative diesel oil-based gas turbine generation to coal-based generation from the Project.

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E. Completion and Self-Evaluation 8. The project completion report (PCR), circulated in October 1999, confirmed that the Project was mostly implemented as envisaged at appraisal, but with a major delay. The work under the single turnkey contract included (i) design, manufacture, delivery, and installation of boilers and electromechanical equipment including all associated auxiliary equipment and apparatus; (ii) basic and detailed design and delivery of related equipment, materials, and supplies, and construction of the associated civil and architectural works such as port facilities, cooling water facilities, coal storage yard, ash disposal area, stack, foundations for equipment/plants, powerhouse, appurtenant buildings/structures, and other related works; and (iii) testing, commissioning, and trial operation of equipment and machinery to ascertain that they were functioning in accordance with the contract provisions and guarantees. However, because of the eruption of Mt. Pinatubo in 1991, the proposed transmission line to the Hermosa substation was rerouted to avoid areas affected by the eruption. This involved the construction of a 230 kV transmission line from Masinloc to the Labrador substation in Pangasinan to link with a proposed 500 kV transmission line from Labrador to San Jose (see Map). Public concerns about the environmental impact of the Project led to major delays, and consequent delays in the issuance of the environmental compliance certificate (ECC) by the Department of Environment and Natural Resources (DENR). The matter was successfully resolved through public hearings and intensive dialogue between the Government, NPC, ADB, and the mayor of Masinloc and concerned citizens. Other factors also contributed to the delays including implementation of the environmental management and resettlement plans, land acquisition, and negotiations about financial assistance to be advanced by NPC to the province of Zambales and the municipality of Masinloc. As a result, loan effectiveness was delayed by 41 months and closing date by 42 months. 9. Because of the extensive delays, the Project, which was commissioned in June 1998 instead of the scheduled commissioning in September 1994, made no contribution to the elimination of the severe power shortages, which peaked in 1992 and 1993. By 1998, the power supply situation had substantially improved due to the large number of independent power producers (IPPs) operating in Luzon and the slowdown in demand growth as a result of the Asian financial crisis. Despite the setback, the financial internal rate of return (FIRR) and economic internal rate of return (EIRR) were recalculated in the PCR at about 17% and 29%, respectively, higher than the appraisal estimates of 15% and 14%. The improvements were mainly due to higher retail tariffs and customers’ willingness to pay. The execution of the associated TA was also delayed for 2 years, but the TA was considered successful since it had largely achieved its objectives. Overall, the Project was rated generally successful.6 The PCR recommended that NPC develop a more effective strategy for dealing with issues that contributed to implementation delays, such as land acquisition and involuntary resettlement; and that ADB further its assistance to NPC to strengthen the institutional capability in managing social issues. F. Operations Evaluation 10. This project performance audit report (PPAR) assesses various aspects of the formulation, design, implementation, and sustainability of the Project, as well as its socioeconomic, environmental, and institutional development impacts. The assessment is based on a review of ADB documents, discussion with ADB staff, and findings of the Operations Evaluation Mission (OEM), which visited the project site at Masinloc, in Zambales, and Manila during 20–31 May 6 Using the previous three-category rating scheme (generally successful, partly successful, and unsuccessful).

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2002. In Manila and during the site visit, the OEM held discussions with NPC officials, Department of Energy (DOE), DENR, the province of Zambales and the municipality of Masinloc, representative of IPPs, Manila Electric Company (Meralco) as a representative of downstream distribution companies, and key industrial/commercial customers. Copies of the draft PPAR were sent to the Government, NPC, and the concerned ADB departments for review; all comments received were considered in finalizing the PPAR.

II. PLANNING AND IMPLEMENTATION PERFORMANCE A. Formulation and Design 11. The resurgence of growth in the demand for power starting in 1987 had severely stressed the limited and unreliable power generation capacities. As a result, increased forced power outages seriously constrained economic recovery. ADB’s operational strategy for the power subsector was to help augment generation capacities and, in so doing, remove the bottleneck and facilitate economic growth and poverty reduction. The Project was considered consistent with this strategy, despite questions raised at loan approval about the wisdom of financing additional generation capacity instead of rehabilitating existing power plants or improving the distribution network. 12. The feasibility study commissioned by NPC envisaged the use of imported coal (i.e., Lymington coal from Australia) mixed with local coal (i.e., Semirara coal) on a 50:50 basis. However, it was decided during appraisal to use imported coal only, mainly for better operational efficiency and environmental benefits as imported coal had a more assured supply, higher heat value, and lower ash content than local coal (footnote 2). The coal specifications and the coal-fired design have been appropriate.7 First, compared with natural gas and diesel that would also have to be imported, coal is much cheaper and more abundantly available (from Australia, the People’s Republic of China, and Indonesia). Therefore, importing coal represents much less stress on the country’s balance-of-payment and enhances its energy security. This does not necessarily contradict ADB’s operational strategy, which emphasized enhancement of operating efficiency as well as the use of indigenous energy resources, since the domestic coal supply was not reliable and the very low quality of coal would have severely impaired the operational efficiency of the units.8 Second, the main concern associated with coal-fired generation, i.e., environmental protection, has been well addressed into the design with state-of-the-art pollution control (para. 15). 13. As designed, MTPP consists of two generating units of 300 MW each, the first financed under the Project, and the second under Loan 1398-PHI (footnote 3). The units are of identical design and each is rated for 21 kV output and provided with a unit transformer of 21 kV-230 kV, 353 megavolt-ampere (MVA). Station power is provided by 230 kV-7.2 kV, 27/45 MVA transformers and unit auxiliary transformers of 21 kV-7.2 kV, 34 MVA rating. MTPP’s cooling and steam cycle utilizes saltwater from the adjacent Oyon Bay for cooling (condensing) and treated freshwater from an adjacent source (Lawis River) for steam makeup. Cooling water is discharged back to the bay through a discharge canal that extends about 650 meters (m) from the shoreline. The cooling water intake structure is also extended into the Bay and is remote

7 The burners have staged combustion, low excess air design, utilizing low-sulfur coal with heat value of about 6,200

kilocalories/kilogram and about 18% ash. 8 Rather than domestic coal, NPC has exploited and utilized geothermal and hydropower resources that the

Philippines is endowed with.

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from the heated discharge. The intake structure and the discharge canal are both adequate to support MTPP’s rated output as is the treatment facility for the river water for steam makeup. 14. Coal is delivered to the plant site via ocean-going bulk ships. It is off-loaded to a conveyor system at an extended jetty with dual auger-type unloaders and conveyed to the coal storage area. This area has a design capacity of 60 days of coal at maximum plant generation. The unloading facility is capable of unloading a typical shipment of about 70,000 tons in about 5 days. A failure of one of the augers results in extended dockage time for the ship, but should not result in a shortage of fuel for generation provided the typical inventories of 30-day supply are maintained. Control and monitoring of the generation process are accomplished by a fully computerized control room with multiple monitors and servers. In the event that a unit monitor fails, all control functions are moved to a backup station, which has fully multiple control and monitoring capability. In the event of a total failure of the control room, control can be maintained at the unit level for each generating unit and for the common facilities. 15. In general, environment protection has been well incorporated into the plant design, including the exclusive use of low-sulfur coal to control sulfur dioxide (SO2) emissions, combustion at minimal excess air to reduce nitrogen oxides (NOx) emissions, a stack height of 150 m, electrostatic precipitators (ESPs) with an efficiency of 99.5%, limitations on cooling water discharge temperatures, emission monitoring, reforestation, and various measures in coal handling to limit dust dispersion. The design conforms to the ECC granted by DENR. 16. In addition to these pollution control measures, other environmental issues such as monitoring and alternative design using new technologies such as FBC were addressed through the associated TA (para. 5). FBC, in particular, was viewed to have significant environmental benefits when combusting coal with low heat values and high ash content. However, since only imported high-quality coal would be used, FBC was deemed unnecessary for the Project since it would increase costs for NPC without significant additional environmental benefits. In the event that a decision is made in the future to switch to domestic coal, FBC would be a cost-effective technology and should be considered. 17. Overall, the OEM regards the Project as a least-cost option to meet the growing energy demand at the time. Rehabilitation of the aging oil-fired facilities was not an economically viable option. Other energy sources including nuclear, geothermal, and hydropower (the latter two have been explored and utilized by NPC to a major extent in other locations) were constrained by various factors including limited availability and low reliability, and political considerations. The MTPP equipment was well designed. The layout of the facilities makes good use of the site and allows for efficient coal handling, ash handling and disposal, and maintenance of the major equipment has been enhanced by attention to access requirements. B. Achievement of Outputs 18. The OEM inspected the generation plant and associated facilities and confirmed that all project components were implemented as envisaged at appraisal . Although not a direct part of the Project, the originally planned 230 kV transmission lines from Masinloc to the Hermosa substation in Bataan to be used to evacuate MTPP’s output was rerouted to the newly built Labrador substation after the eruption of Mt. Pinatubo. Power is now transmitted from MTPP to

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the Luzon grid via a gas-insulated switching station9 and a 230 kV double-circuit transmission line of about 94 km.10 However, the entire transmission line between MTPP and the Labrador substation did not start operation until May 1999, about 5 months after the second unit was commissioned. During this time, a temporary arrangement was made to evacuate the power by way of completing the first 5 km and tapping to the existing 230 kV Botolan-Labrador line at a reduced capacity. This adversely affected MTPP’s operational performance during the initial months (para. 27).11 19. Generally, the OEM found the quality of the equipment procured under the Project, construction, and civil works to be high to satisfactory. However, the site inspection and interviews with key MTPP operation personnel revealed some implementation issues and disputes. First, the four remote environmental monitors procured under the Project to be used for conducting continuous air quality monitoring around MTPP have all stopped functioning.12 Although the breakdown occurred within the warranty period, the supplier was not able to fix the instruments. Second, both generation units experienced outages shortly after their commissioning (para. 26). Third, significant problems were encountered with the coal handling system, including the water spray system and the bulldozer used for compaction (para. 37). Fourth, one of the two coal ship unloaders broke down at the time of the OEM’s visit (para. 31). Fifth, the turnkey contract specified that the under frequency (UF) relay tripping on the MTPP units should not be higher than 58.2 hertz (Hz). The actual UF relay tripping was set at 58.0 Hz by the manufacturer, which met the requirement of the contract. However, the Grid Code, which was promulgated in June 2001 after the commissioning of MTPP, requires all generating units to remain in synchronism for at least 5 seconds if the system frequency momentarily falls to 57.6 Hz, lower than the 58.0 Hz set for the MTPP units.13 This deviation has caused serious problems in operation as the DOE has repeatedly requested MTPP to lower the frequency to 57.6 Hz to reduce the downtime for the Luzon grid. On the other hand, the manufacturer has warned that if MTPP lowers this frequency setting and damages the turbines as a result, the damage would not be covered by the manufacturer’s warranty. On the whole, however, the facilities built under the Project have been operating well, and MTPP has reached its design output (para. 27). C. Cost and Scheduling 20. The PCR estimated that the actual total cost amounted to $429.3 million equivalent, 3% lower than the appraisal estimate of $441.0 equivalent. The ADB financing amounted to $196.8 million, and the balance of $3.2 million was cancelled. The foreign exchange portion was $393.5 million, 12% higher than the appraisal estimate of $350.0 million; and the local currency portion was $35.8 million equivalent, 61% lower than the appraisal estimate of $91.0 million equivalent

9 The OEM noted the adoption of a state-of-the-art gas insulated switching station. Though more expensive than the

conventional open design, it can significantly reduce the maintenance required in view of the atmospheric coal dust and increase the system’s reliability.

10 Each circuit is designed with four conductors per phase; thus, either circuit can support the rated output of both generating units.

11 Ideally, it would have been better to include the portion of the transmission line from MTPP to Labrador substation in Stage I of the Project to avoid delays. However, technical and financial considerations required the transmission components of the Masinloc Thermal Power Scheme to be financed and implemented through a separate project, which was cofinanced by ADB (Loan 1398-PHI, footnote 3), World Bank, and Kreditanstalt für Wiederaufbau.

12 As a result, NPC resorts to manual snapshot monitoring of ambient air quality on a quarterly basis. 13 The UF tripping limitation is significant as the rotating turbo-generator plant is subject to significantly higher

stresses when operated at a speed lower than the rated frequency. Manufacturers often try to restrict the permitted operating frequency range so as to reduce manufacturing cost. However, system stability considerations make it desirable for a generator to “ride through” a system frequency disturbance without tripping, since such tripping would reduce the ability of the system to recover stability after a disturbance.

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(Appendix 1). After extensive deliberations within NPC’s financing department and several discussions with the OEM, NPC confirmed that the PCR estimate accurately reflected the costs to NPC.14 Despite the total cost underrun, the actual project cost excluding interest charges during construction was higher than the appraisal estimate, indicating efficient project execution in terms of time requirements (despite the initial delays) but higher-than-estimated costs of the project components.15 The latter was mainly attributable to the fact that the appraisal estimate was prepared in 1990 while the turnkey contract was awarded in 1994; this rendered the appraisal estimate outdated given general cost increases in the meantime. Regarding the foreign exchange overrun, the civil works portion of the contract was awarded to a foreign subcontractor.16 This had implications for the currency of payments. The total cost for all civil works was $83 million, only slightly higher than the appraisal estimate of $81 million. However, the foreign subcontractor demanded that all payments be made in foreign currency. While the foreign subcontractor paid local subcontractors in local currency, NPC was not aware of such costs. As a result, NPC reported zero for the actual local costs for civil works in Table A1.1.17 21. Appendix 2 gives the project schedule as appraised and as implemented. As noted in para. 8, loan effectiveness was delayed for about 41 months due to difficulties encountered in issuance of the ECC, land acquisition, and implementation of the resettlement action plan.18 Tendered as a turnkey contract through international competitive bidding procedures, the power plant construction, once started, took 39 months, some 3 months shorter than anticipated. D. Procurement and Construction 22. All ADB-financed civil works and equipment were procured in accordance with ADB’s Guidelines for Procurement. Turnkey contracts are generally an industry standard for construction of coal-fired power plants. The use of a turnkey contract was anticipated at appraisal as the most expedient method to construct MTPP. However, there were initial concerns that the turnkey method may result in higher construction costs than multicontract packaging. Considering the ensuing start-up delays (which would have caused chain effects in incurring cost overruns), it is likely that the turnkey method resulted in cost savings and shortened the construction period, perhaps by as much as a year (compared with the multicontract alternative). Although such an alternative—three contracts—was successfully

14 The PCR for Loan 1398-PHI (footnote 3), which financed the construction of Unit 2 plus various transmission lines

and substations, suggested that there was an additional cost of about $91 million associated with Unit 1. However, with assistance from ADB staff and NPC, the OEM determined that the “additional” cost referred to the foreign exchange shortfall caused by the cost overrun in foreign exchange, even though the total cost of the Project was within the appraisal estimate. The foreign exchange shortfall was financed through an ADB-guaranteed bond issue arranged in conjunction with Loan 1398-PHI, and the balance of the Y12 billion bond proceeds was used to finance other components of Loan 1398-PHI.

15 It appears that, in order to minimize interest payment, NPC had used part of the foreign currency financing (including the Japanese bond issue) for the subsequent Loan 1398-PHI (footnotes 3 and 14) to pay for ADB’s interest and other charges during construction for the Project as the total interest during construction for Loan 1398-PHI was $24.6 million more than the appraisal estimate while the interest charge for the Project was $26.8 million below the appraisal estimate.

16 As this was a turnkey contract, the decision regarding selection of subcontractors was made by the principal contractor.

17 As an approximation, the actual local cost may be estimated at about 20% of the actual total cost using the ratio underlying the appraisal estimate.

18 According to NPC, the ECC processing was greatly delayed by the then new DENR requirement of public acceptability of the Project. DENR initially did not have specific guidelines on how the public acceptability requirement had to be complied with.

8

used by NPC to construct the coal-fired thermal power plant in Calaca, Batangas,19 the turnkey method, given the situation at Masinloc, appears to have been the most expedient and least-cost choice for constructing MTPP. 23. The performance of the turnkey contractor was generally satisfactory. The quality of construction of the generation plant and associated facilities is excellent. However, in a few noncritical areas, inadequate coordination of subcontractor works resulted in poor integration of systems, such as the air conditioning ductwork for the environmental laboratory. Better planning and coordination by the turnkey contractor would have eliminated those few minor problems. E. Organization and Management 24. NPC implemented the Project through its PMO that had only 10 staff members. On hindsight, the turnkey approach significantly reduced the additional stress from the limited capacity of the PMO. However, the downside was that the PMO had to rely heavily on the inputs of the consultants for design, detailed engineering, preparation of bidding documents, and construction supervision for the turnkey contract.20 Close to $12 million, or almost 3% of the total project cost, was spent on consulting fees for this purpose (Appendix 1). In addition to PMO staff, NPC also dispatched a team of engineers to work with the project consultants and contractors. Some of them later became key managerial personnel for the operation of MTPP. 25. Project implementation experienced a major start-up delay due to difficulties encountered in acquisition of land and rights-of-way, and issuance of ECC (para. 21). This was partly caused by the underestimation of such difficulties by NPC and inadequate project preparation, as NPC lacked experience in dealing with complex public acceptance and resettlement issues. At the time, ADB had yet to develop its policy on resettlement,21 and preparing a resettlement action plan was not yet practiced in the Philippines.

III. ACHIEVEMENT OF PROJECT PURPOSE A. Operational Performance 26. The OEM regards MTPP’s operation and maintenance to date as satisfactory. The upkeep appears to be according to generally accepted utility practice. Nevertheless, there have been two significant failures of major equipment, one affecting each unit. In Unit 1 (the project unit), seawater intruded into the steam flow in August 1999, and damaged the turbine. The result was a significant cost for repair and loss of production. Unit 2 suffered a stator fault in January 2000 due to an apparent failure of the excitation protective relaying. This also resulted in a significant cost for repair and downtime of the unit with the corresponding loss of production. Both incidents are currently the subject of discussion with the turnkey contractor and insurance providers so as to resolve the causes, costs inflicted, and prevention of future incidents. During the OEM’s site visit, minor repair and cleaning were under way on the conveyor system, which resulted in marked but localized spillage of coal. A few key components, such as the coal ship unloader, were affected by the excessive procedural requirements at NPC for procuring replacement parts. Only one of the two unloaders was

19 An additional fee for the overall coordination of the various contracts was paid to the supplier of the turbines and

generators. 20 As agreed to by ADB at appraisal, NPC retained the services of the same international consulting firm that carried

out the feasibility study for detailed design and construction supervision. 21 ADB. 1995. Involuntary Resettlement, Manila.

9

operational that lengthened vessel turnaround times, and possibly resulted in demurrage charges. 27. Since their commissioning in June and December 1998, both units have been used for base-load operation in the Luzon grid. During the initial months, however, the output was limited by the transmission line constraints (para. 18). Coupled with the two unit failures, the plant factor22 (Appendix 3) and availability23 (Appendix 4) were low. Since mid-2000, operational performance has improved significantly. In 2001, MTPP’s average plant factor was 70% (over 90% for some months), and availability of Unit 1 was 84%. In 2002 (through April), the plant factor was 75% and availability of Unit 1 was 97%,24 despite the current generation capacity surplus in Luzon due to a large number of IPPs. MTPP’s high utilization has been attributable to its relatively low generation costs and the fact that the two units of 600 MW each at an IPP plant in Sual, which was commissioned in April 1999, are too large for base-load operation in the relatively small grid in Luzon with a total available capacity of 5,300 MW. MTPP’s generation depends on an assured supply of coal of design quality and properties in a timely manner without significant delays in off-loading. The concerns on timely procurement of spare parts and repair apply equally to the coal-handling facilities. Overall, however, MTPP has been providing a stable and economical power supply for Luzon, and has helped improve the conditions for economic development and investments amid the current public debate on the role of IPPs in the power supply in the Philippines. The improved power supply has allowed a growing number of new connections in rural Luzon and has met the demand for power by major industrial and commercial customers, as indicated by interviews with key customer representatives including a small utility cooperative near MTPP and several large industrial and commercial customers in energy-intensive industries. B. Performance of the Operating Entity 28. As of January 2001, NPC had 26 power generation plants in Luzon with a total installed capacity of 3,486 MW.25 Table 1 gives some key operational and financial indicators for NPC. Generally, NPC’s financial performance has been deteriorating, particularly after the Asian financial crisis in 1997. Despite the fact that the wholesale tariff was the second highest in the region, NPC’s operating revenue in 2001 was only 6% higher than its operating expenditure. When interest payments and other charges were deducted, NPC incurred a net loss of about P10.4 billion. The return on rate base, or the rate of return on average net fixed assets as specified in the loan covenants, declined steadily from 8.2% in 1996 to 2.9% in 2001, far below the covenanted level of 8% (Appendix 5). The debt-service coverage ratio experienced a similar decline, from 1.6 in 1996 to 1.0 in 2001, below the covenanted level, set at 1.0 for 1996 and 1997, and 1.3 from 1998 onward. NPC’s compliance with the loan covenant on a self-financing ratio not less than 20% could not be independently confirmed by the OEM because of lack of information. However, the PMO official interviewed indicated that generally, 20% of total financing for NPC’s capital expenditure was from NPC’s internal cash generation while 80% was from external sources.

22 Plant factor is defined here as net energy output/(plant rated output x number of hours in the period considered). 23 Availability is defined here as the ratio of hours a unit was capable of operation to the total number of hours in the

period considered. 24 Availability for Unit 2 was similarly high, namely 90% for 2001 and 91% for 2002 (through April). 25 Since January 2001, however, several aging oil-based units have been decommissioned. According to NPC, with

additional capacities from IPPs, the total capacity available in Luzon is about 5,300 MW.

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Table 1: NPC Financial Performance, 1996–2001

Indicator 1996 1997 1998 1999 2000 2001 Sales (GWh) 33,381 36,442 37,321 36,987 37,320 39,948Sales Growth (%) 7.6 9.2 2.4 (0.9) 0.9 7.0Average Rate (P/kWh) 1.96 2.15 2.58 2.65 3.12 3.40Operating Revenue (P million)

63,635 77,144 86,611 89,686 100,119 115,698

Operating Expenditure (P million)

50,317 65,519 79,696 81,196 94,681 108,861

Rate Base (P million) 161,536 161,808 215,053 251,989 244,756 236,305RORB (%) 8.2 7.2 3.2 3.4 2.2 2.9Debt-Service Coverage Ratio

1.6 1.0 0.9 0.9 0.7 1.0

GWh = gigawatt-hour, kWh = kilowatt-hour, rate base = the average value of the net fixed assets in operation at the beginning and the end of the year, RORB = return on rate base. Source: National Power Corporation. 29. Despite the good performance of MTPP, NPC’s financial performance has not been satisfactory. The poor performance is at least partly attributable to the fact that NPC signed approximately 40 power purchasing agreements (PPAs) with IPPs across the Philippines at the height of the power crisis in the early 1990s and thereafter. These “take or pay” contracts oblige NPC to pay a minimum capacity charge regardless of whether the capacity has been used or not. This became a problem when the growth in NPC’s energy sales slowed down in the aftermath of the Asan financial crisis. During the period 1996-2001, NPC’s operating revenue increased at an average annual rate of 12.7%, significantly below the average annual growth rate of NPC’s operating expenditure of 16.7%. Depending on the schedule and the manner in which the planned privatization will be carried out, the poor financial health of NPC may have an adverse impact on the long-term performance of the Project (para. 33). C. Financial and Economic Reevaluation 30. Appendix 6 contains the recalculated FIRR and EIRR for Units 1 and 2 combined.26 All costs and benefits are denominated in pesos in 2002 constant prices. As summarized in Table 2, the recalculated FIRR is 21.4%, higher than the appraisal and PCR estimates of 14.9% and 17.2%, respectively. The very high FIRR is due to the high utilization of the two units for meeting the base load and the high tariffs. The recalculated EIRR is 29.7%, also higher than the appraisal and PCR estimates of 14.5% and 28.8%, respectively, mainly due to the higher average willingness-to-pay as estimated for Luzon by the OEM based on interviews with key customers and NPC’s customer profile (e.g., type of customers and their capacity requirements).

26 The financial and economic reevaluation has been carried out for combined Units 1 and 2 as they have identical

design, are functionally inseparable, and share all the auxiliary components.

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Table 2: Summary of Financial and Economic Reevaluation (%)

Item Appraisal PCR PPAR FIRR 14.9 17.2 21.4 EIRR 14.5 28.8 29.7

EIRR = economic internal rate of return, FIRR = financial internal rate of return, PCR = project completion report, PPAR = project performance audit report. Source: Appraisal Report, PCR, and Operations Evaluation Mission.

D. Sustainability 31. Proper and efficient maintenance is essential for the effective operation of a power plant and is key to its long-term sustainability. Plant maintenance at MTPP is administered through a system of corrective maintenance work orders, which identify the necessary work to be done and allow a prioritization of maintenance demand and resource allocation. However, this system is routinely hampered by the difficulty in obtaining replacement parts. The present system for procuring parts or equipment, which is subject to various restrictions on procurement mandated by NPC and government regulations, is time-consuming and presents a significant obstacle to efficient and expedient maintenance. At times, key components, such as a coal ship unloader, have been immobilized due to the lengthy process for procuring replacement parts. With only one of the two unloaders operational, vessel turnaround times are lengthened and high demurrage charges can result. 32. MTPP is scheduled for an annual 45-day maintenance outage for each unit and a 75-day outage every 5 years. The OEM was informed that the 5-year shutdown is mandatory under the supplier’s warranty and will be attended by the supplier with compensation to them. While the OEM finds this procedure and schedule to be reasonable and prudent, it also feels that the time periods for maintenance could be somewhat reduced in the future without any sacrifice in the quality or adequacy of preventive maintenance or repair. 33. As the two units have been used for base-load operation and have a very high FIRR, the Project is likely to be financially sustainable. However, the financial health of NPC may become a concern if the planned privatization of its generation and transmission companies, wholly or partly, does not take place. If it materializes, privatization would be a welcome move in terms of provision of adequate operating capital, prompt procurement of spare parts, and generally more commercially oriented practices.

IV. ACHIEVEMENT OF OTHER DEVELOPMENT IMPACTS A. Socioeconomic Impact 34. By providing a reliable supply of electricity, the Project has contributed to the increasing rural electrification in Luzon and meeting the demands for power by key industrial and commercial customers and, thus, has facilitated economic development. According to Zamco1 Electricity Cooperative interviewed by the OEM, total electricity usage in its service areas has been growing at about 10% per year due to increasing rural connections. The increase was made possible partly by the commissioning of MTPP, which provides relatively inexpensive and

12

reliable electricity. Over the years, NPC has also been supporting local community development by building schools and roads in northern Luzon. 35. Additional socioeconomic impacts of the Project were achieved during construction with the resettlement of 198 project-affected families (PAFs), or about 1,000 affected persons, living at the project site. Despite the fact that at the time ADB had yet to develop its own resettlement policy and preparing resettlement programs was not yet widely practiced in the Philippines (para. 25), NPC developed and implemented a resettlement program in collaboration with the municipality of Masinloc. The resettlement program had three objectives: (i) to relocate the families within the boundaries of the project site after they had been compensated; (ii) to develop a resettlement program that would be socially and economically acceptable to PAFs; and (iii) to define the responsibilities of NPC offices and PAFs in planning, implementing, monitoring and evaluating of the resettlement program. The main features of the resettlement program were three compensation options to PAFs: (i) a house and lot at the resettlement site, (ii) cash compensation for a house and a lot at the resettlement site, and (iii) cash compensation for those who would relocate outside the resettlement site. NPC also provided two livelihood programs, with one administered by the association of relocatees at the resettlement site, and the other managed by the local government for the rest of the residents of Masinloc. 36. With assistance from NPC’s community relations coordinator, the OEM carried out in-depth interviews with 51 PAFs. Detailed information and analysis are presented in Appendix 7. Generally, despite some outstanding issues, NPC has fully achieved the first objective of the resettlement program and substantially or partly achieved the two others. The livelihood program managed by the local government has been well run and highly successful; the one administered by the association of relocatees has failed for various design and implementation reasons. Through the interviews, the OEM identified the main issues still to be resolved: (i) lack of drinkable water at the resettlement sites (e.g., high salinity of the water extracted from deep wells), (ii) lack of job opportunities and reduced income for some PAFs, (iii) delayed transfer of land titles to PAFs, and (iv) disputes over compensation amounts. B. Environmental Impact 37. Environmental protection has been well incorporated in the design of the Project (para. 15). First, MTPP meets the emission standards for SO2 by using low-sulfur coal, i.e., less than 1% sulfur on an as-received basis. Second, to limit emissions of NOx formed during combustion in the presence of excess air, MTPP’s burners are designed to minimize such excess air. Third, fly ash—the major component of particulate matter, which is ejected in the exhaust of MTPP—is abated by the use of ESPs. Each MTPP generating unit is equipped with two ESPs, which have 99.5% removal efficiency. Fourth, to abate pollution and noise, NPC has embarked on a major effort to plant trees, which function as a buffer zone around the plant area and absorb carbon dioxide generated by the burning of fossil fuels. To date, this effort has resulted in the planting of over 44,400 trees of various kinds including mango, which now bear fruit. Fifth, MTPP emits cooling water discharge and runoff from the ash disposal pits. The concern associated with the cooling water discharge is its temperature. DENR stipulates that the temperature rise in the mixing area at the point of cooling water discharge should not exceed 3 degrees centigrade. The plant design abated this effect with the construction of an approximately 650-m-long discharge channel, which allows mixing of the warmed cooling water before it reaches the discharge point. The runoff from the ash disposal area is collected in a settling basin and then sampled before it is discharged off the site. Records indicate that this is effective. Sixth, coal is delivered by ship and conveyed by covered belt to the storage yard. Bottom ash and some fly ash are disposed of in an on-site ash pond. To date, the bulk of the fly

13

ash has been disposed of by conversion to commercial use by a construction company that also provides off-site transportation.27 Coal inventory is limited and the storage is compacted. A water spray system is in place for dust control and temperature is monitored to prevent spontaneous combustion in the coal storage. These features conform to the requirements of the ECC and have contributed to the overall environmental compliance of MTPP. However, the OEM noted that the water spray system was temporarily out of service and the bulldozer used for compaction was subject to outages for lack of spare parts. The OEM also noted that the ECC called for a physical windbreak around the coal storage areas. The tree planting efforts provide a form of windbreak for MTPP; additional plants around the perimeter of the coal storage yard itself would be more effective. 38. The ECC, several memorandums of agreement signed between NPC and the local government unit (LGU) and DENR, and ADB loan covenants require various forms of emission control and monitoring by the plant operators. The Project addressed this issue by (i) providing state-of-the-art environmental monitoring equipment; and (ii) the associated advisory TA, which helped NPC improve its environmental monitoring capacity. The OEM confirmed that NPC had established an environmental analysis laboratory and maintained competent full-time environmental personnel. These personnel perform monitoring, maintain records of such, analyze samples, and interface with a multipartite committee consisting of NPC, LGU, DOE, DENR, and nongovernment organization (NGO) representatives who perform joint quarterly sampling exercises with the MTPP Pollution Control Officer and staff. 39. Plant emissions at the stack are monitored by a state-of-the-art continuous emissions monitoring system (CEMS), which is maintained by the control software and data acquisition system. CEMS measures SO2, NOx, and other data on an hourly basis. In addition, four remote monitoring stations were established in nearby villages to provide continuous monitoring of these emissions as they affect the surroundings of the MTPP site. Although equipped with continuous recording monitors, these instruments failed (para. 19). The warranty considerations are being discussed with the supplier. To provide the required quarterly monitoring for the multipartite committee, NPC staff are utilizing portable instruments at present. The results of the past four quarterly inspections of ambient air and water quality as well as several snapshots of the printout of the CEMS on stack emissions are shown in Appendix 8. The results indicate that MTPP’s environmental impacts are well within the limits set by DENR. C. Impacts on Institution and Policy 40. Appendix 9 shows NPC’s organization chart. NPC has been divided into different operating entities, e.g., transmission companies (TRANSCOs) and generation companies (GENCOs).28 Such a structure is conducive to the planned privatization, which can take place either with a particular company or facility, or a group of companies. Although the Project did not contribute to restructuring NPC directly, it was part of ADB’s long-term assistance program consisting of project loans, program loans, and TAs in support of sector restructuring. 41. The main impacts of the Project on institutional development were achieved through the associated advisory TA, which accomplished its main objective of improving NPC’s environmental monitoring capacity. Although problems in accessing the site and issuing the

27 The company purchases a portion of the ash from NPC and converts it into construction materials. Although the

resulting revenue for NPC is relatively small, the main benefit of this arrangement is that it defers the need to build a new ash pond, which would not only be costly but would also have adverse environmental impacts.

28 MTPP belongs to GENCO 2.

14

ECC delayed the TA by about 2 years, the consultants’ report established a baseline air quality monitoring program that was the basis for the present monitoring program at MTPP and contributed to the creation of the multipartite monitoring committee. The TA was instrumental in convincing NGOs and others opposing the use of coal for power generation that MTPP could be designed and operated in an environmentally sustainable manner. The assessment of the effects of the cooling water discharge into Oyon Bay showed that the effects would be negligible and provided a basis for the eventual design of the discharge channel. The discharge channel design and orientation to the site have proved successful and performance has been as indicated by the assessment. The OEM’s review of the activities, reporting, field measurement practices, and the laboratory and portable equipment of the environmental personnel at MTPP indicated that the training under the TA was successful. Interviews with key NPC environmental personnel indicated they were well satisfied with the training received. Overall, the TA is considered successful. 42. Another source of the Project’s positive impacts on institutional development was the work with international consultants and contractors in preparing and implementing the Project. This work allowed NPC staff to gain substantial knowledge in designing and supervising coal-fired generation projects. The Project had no discernible policy impacts.

V. OVERALL ASSESSMENT A. Relevance 43. The Project was highly relevant in that it aimed to address the country’s severe power shortages during the early 1990s, which hindered economic recovery. It was consistent with ADB’s operational strategy in the power sector at the time, which gave priority to augmenting power generating capacity to facilitate economic growth and poverty reduction. The relevance has been reduced somewhat due to (i) delay in implementation that prevented the Project from contributing to alleviation of the power crisis, and (ii) the current lower demand for power resulting from slower-than-expected economic growth and the surplus generation capacities due to a large number of IPPs operating in Luzon. Overall the Project is as assessed as relevant. B. Efficacy 44. Since their commissioning, the two 300 MW units at MTPP, including the Project-financed unit, have been used for the base-load operation in the Luzon grid. With its high plant factor and availability, the Project has achieved its intended purpose of efficiently and economically meeting the capacity and energy requirements in Luzon and, hence, is assessed as highly efficacious. C. Efficiency 45. The Project provides least-cost generation of electricity. Despite the initial delay of about 3.5 years, the execution of the Project under a single turnkey contract was efficient, and was within the budget and revised time schedule. With a high FIRR of 21.4% and an even higher EIRR of 29.7%, the Project is assessed as efficient. D. Sustainability 46. Plant maintenance is generally satisfactory. With its high FIRR, the Project is likely to be financially sustainable. Nevertheless, the OEM identified the tedious procedures for procuring

15

spare parts at NPC as a main factor impeding the operational sustainability of the Project, which may also be adversely affected by the poor financial performance of NPC. However, the planned privatization of NPC’s generation companies is expected to have positive impacts on MTPP’s sustainability by streamlining procurement procedures and improving financial management. Overall, the Project is likely to be sustainable. E. Institutional Development and Other Impacts 47. The Project has had moderate but positive impacts on the institutional development of NPC for project management and operations through work with the international consultants and contractors. In addition, the associated TA enhanced NPC’s in-house capacities in environmental monitoring and management, as evidenced by the well-equipped and well-trained environmental management department, and the conformity of MTPP’s air and water emissions with the Philippine national standards. By providing reliable and affordable electricity to facilitate economic growth, rural electrification and poverty reduction in Luzon, the socioeconomic impacts of the Project have been mainly positive. After initial problems, the resettlement of 198 households living at the project site was handled satisfactorily. The resettlement program has been fair, comprehensive, and socially responsible, but there are still some problems in terms of drinking water, economic opportunities for PAFs, land ownership, and disputes over compensation amounts that need to be addressed. Overall, the Project has had moderate environmental and socioeconomic impacts. F. Overall Project Rating 48. Based on the preceding considerations, the Project is rated successful.29 G. Assessment of Asian Development Bank and Borrower Performance 49. ADB fielded eight missions during project preparation and implementation. However, given the geographic proximity of ADB and NPC, the number of missions did not reflect the full scope of ADB’s inputs to project preparation and implementation. Available records indicate that ADB’s project and environment and social divisions, interacted intensively with NPC, LGUs, and NGOs, particularly in addressing issues related to land acquisition, resettlement and compensation, and environmental impacts. Project design proved to be of high quality and there was virtually no variation from the original design (except for the rerouting of the transmission line). Overall, ADB’s performance was satisfactory. The performance of NPC was generally satisfactory as it promptly implemented the Project once the resettlement and environmental issues were resolved. However, as the Project was the first time in NPC’s project implementation history to involve designing and implementing a resettlement program, there were deficiencies in the process (Appendix 7). Learning from the initial difficulties, NPC established a Social Engineering Department to specialize in rights-of-way issues and community development.

29 Using the current four-category rating scheme (highly successful, successful, partly successful, and unsuccessful).

16

VI. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS A. Key Issues for the Future

1. Operational Sustainability 50. Although the Project is generally well operated and maintained, several factors may affect its operational sustainability. In addition to the slow and tedious procedures for procuring spare parts (para. 31), the manner by which the issue of proper setting and time delay of UF relay tripping on the MTPP units is resolved will affect the sustainability of the Project (para. 19). A decision toward a lower UF relay tripping would risk significant equipment damage and outage while keeping the status quo may result in more blackouts, which would not only adversely affect the revenue attributable to MTPP but also subject the wider economy to losses. This dilemma could be resolved by certain transmission improvements, but the possible addition of a 500 kV transmission loop south from MTPP to Hermosa substation is probably only on a 10-year planning horizon. This aspect of the future operation of MTPP needs to be resolved soon and in the most cost-effective manner.

2. Future Privatization of the National Power Corporation 51. With ADB’s support, NPC has embarked on a restructuring program under which its generation and transmission companies will be privatized, wholly or partially. Most NPC officials interviewed expect the privatization to have positive impact on the operations and sustainability of MTPP as the flagship of NPC’s generation assets, by introducing more commercial practices and reducing political interference. However, the timetable has been postponed several times and it is hoped that privatization will take place in the second half of 2003.

3. Controversy Around independent power producers and Power Purchasing Agreements

52. The power sector in the Philippines is currently witnessing a public debate about the role of IPPs and the high electricity tariffs partly caused by the PPAs that NPC signed with them. These PPAs are “take or pay” in nature, obligating NPC to purchase a minimum capacity installed, typically 80%, regardless of whether the electricity is used or not. There is increasing public pressure for NPC to lower its tariffs, which is likely to cause further deterioration of its financial performance. On the other hand, MTPP is clearly a positive factor amid the controversy and has been playing a crucial role in providing economical and reliable power supply in Luzon. B. Lessons Identified

1. Front-End Delays and Resettlement Program 53. The Project suffered from a major front-end delay of about 3.5 years. It may be preferable for projects of this type to acquire the necessary land and rights-of-way before loan approval. Regarding resettlement, the following is essential: preparation of a comprehensive resettlement program by a team of experts from diverse disciplines, a separate environmental impact statement for the resettlement site, and a feasibility study of livelihood programs; engagement of a full-time community organization and relations officer to assist PAFs in their adjustments; and participation of PAFs in the design and implementation of the livelihood programs (Appendix 7). In short, resettlement should be based on a time-bound action plan of documented measures, be founded on a sound legal basis and a cogent assessment of the pre-

17

project socioeconomic situation, and be fully communicated to all PAFs. This would facilitate its acceptance by PAFs and allow a clear comparison of what was intended and what was actually achieved.

2. Turnkey Contract as a Key to Smooth Implementation 54. Despite the initial delays, project construction was relatively smooth and within the revised schedule. This was largely due to the adoption of a single turnkey contract for all project components. It is likely that the turnkey approach, compared with multicontract packaging, resulted in cost savings as well as a shortened construction period, perhaps by as much as a year. A downside of the turnkey approach as used in this case was that all the payments were made in foreign currency. C. Follow-Up Actions

1. For Asian Development Bank 55. ADB has been providing major assistance to the power sector in the Philippines, particularly for sector restructuring and development of a competitive electricity market, as exemplified by the ongoing program loan.30 This assistance has been instrumental in overcoming the various physical, institutional, and political constraints to restructuring. ADB should continue such assistance in the foreseeable future, although its focus and recipients may be different after NPC has been privatized. 56. Two financial covenants of the Project—debt-service ratio and rate of return on average net fixed assets—have not been complied with. However, after the privatization, NPC will cease to exist as an operating entity. Different covenants may be needed in ADB’s future assistance to NPC-derived entities.31

2. For the Government 57. The much-anticipated privatization of NPC, which is scheduled to take place in the second half of 2003, should be brought on track without further delay. The OEM feels that, although privatization will not solve all the problems facing the power sector of the Philippines, such as high tariffs and low supply reliability, a well-crafted and transparent privatization program can remove much of the institutional and political barriers that currently hinder the development of a competitive electricity market. Furthermore, it is important that the Government (i.e., Housing and Urban Development Council under the Office of the President) approve a policy on involuntary resettlement at the earliest time possible to minimize costly project delays and ensure fair and socially responsible compensation and livelihood programs for future would-be-affected persons.

3. For National Power Corporation 58. There are some operational issues that may potentially affect the long-term sustainability and viability of MTPP. While all the following recommended measures should be implemented

30 Loan 1662-PHI: Power Sector Restructuring Program, for $300 million, approved on 16 December 1998. 31 While NPC’s generation and transmission companies will be privatized wholly or partly, the remaining assets and

liabilities will be managed by the recently created Power Sector Assets and Liabilities Management Corporation.

18

as soon as possible, to avoid further complications, it is essential that they be completed before NPC’s privatization in the second half of 2003:

(i) The windbreak around the coal-storage yard should be installed to conform to the ECC requirements.

(ii) The four dysfunctional remote monitoring stations, which were designed to

measure ambient air pollutant concentrations, should be repaired. (iii) The outstanding issues related to resettlement should be resolved by NPC,

namely, the ongoing lawsuit against NPC on compensation, providing PAFs with drinking water by constructing water lines, study of the feasibility of providing more assistance to the local economy by constructing a basic market in a nearby area, and transfer of land titles to PAFs.

(iv) As timely procurement of spare parts is a crucial factor for MTPP’s uninterrupted

operations, NPC should streamline its procurement procedures. (v) To avoid possible equipment damage, NPC should operate MTPP with the

existing UF relay settings. Although this may reduce grid security, the risk is small compared with the stability problem caused by the larger size of the Sual units.

Appendix 1 19

PROJECT COST AND FINANCING PLAN

Table A1.1: Cost Breakdown by Project Component ($ million)

Appraisal Estimate Actual Item Foreign Local Total Foreign Local Total A. Base Costs 1. Electromechanical a. Boiler and Auxiliaries 81.00 5.60 86.60 103.19 0.00 103.19 b. Turbogenerator and Auxiliaries 69.00 1.90 70.90 115.06 0.00 115.06 c. Coal-Handling System 43.00 1.50 44.50 33.65 0.00 33.65 2. Civil Works a. Harbor 9.20 5.20 14.40 23.25 0.00 23.25 b. Cooling Water 5.00 8.80 13.80 13.46 0.00 13.46 c. Powerhouse and Stack 8.30 4.00 12.30 18.09 0.00 18.09 d. Others 12.50 28.00 40.50 38.22 0.00 38.22 3. Insurance and Transport 9.00 4.00 13.00 5.95 0.00 5.95 4. Social Costs a. Land/Right-of-Way 0.00 3.00 3.00 0.00 11.62 11.62 b. Relocation/Resettlement 0.00 0.00 0.00 0.00 3.06 3.06 c. Financial Assistance 0.00 0.00 0.00 0.00 11.07 11.07 5. Consulting Services a. Fuel Management 0.50 0.10 0.60 0.00 0.00 0.00 b. Construction Supervision 6.50 0.90 7.40 10.47 1.50 11.97 6. Administrative/Operational Expense

0.00 0.00 0.00 0.00 8.50 8.50

Subtotal (A) 244.00 63.00 307.00 361.34 35.75 397.09B. Contingencies 47.00 28.00 75.00 0.00 0.00 0.00C. Interest During Construction 59.00 0.00 59.00 32.18 0.00 32.18 Subtotal (B+C) 106.00 28.00 134.00 32.18 0.00 32.18

Total 350.00 91.00 441.00 393.52 35.75 429.27 Source: Operations Evaluation Mission.

Table A1.2: Financing Plan ($ million)

Appraisal Estimate Actual Item Foreign Local Total Foreign Local Total Implementation Costs NPC 0.00 61.00 61.00 21.55 35.75 57.30 ADB 171.00 0.00 171.00 190.82 0.00 190.82 JEXIM 120.00 30.00 150.00 148.97 0.00 148.97 Subtotal 291.00 91.00 382.00 361.34 35.75 397.09 IDC Costs NPC 30.00 0.00 30.00 26.18 0.00 26.18 ADB 29.00 0.00 29.00 6.00 0.00 6.00 Subtotal 59.00 0.00 59.00 32.18 0.00 32.18 Total 350.00 91.00 441.00 393.52 35.75 429.27 ADB = Asian Development Bank, IDC = interest and other charges during construction, JEXIM = Export-Import Bank of Japan, NPC = National Power Corporation. Source: Operations Evaluation Mission.

20 Appendix 2

I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV

Project Processing and Pre-Construction

A. Loan Signing

B. Loan Effectiveness

C. Land Acquisition

D. Environmental Compliance Certificate

Construction Stage

A. Generating Plant

1. Design/Manufacturing/Delivery

2. Civil Works

3. Electromechanical Erection

4. Test and Commissioning

Project Completion

Appraisal

Actual

1998

PROJECT SCHEDULE

1994 1995 1996 19971992 19931991

Loan Agreement required that all needed land be acquired before award of the turnkey contract.

Land acquisition requirements complied with on 23 Sep 1994.

Appendix 3 21

GENERATION OUTPUT DATA FOR MASINLOC THERMAL POWER PLANT

Auxiliary Net Plant Year/ Gross Generation (MWh) Usea Output Factorb Month Hours Unit 1 Unit 2 Plant (MWh) (MWh) (%) Remarks 1999 Jan 744 48,794 100,355 149,149 11,293 137,856 30.9 Output constrained by transmission limits Feb 672 71,710 133,848 205,558 14,832 190,726 47.3 Output constrained by transmission limits Mar 744 22,466 162,637 185,103 11,765 173,338 38.8 Output constrained by transmission limits Apr 720 180,855 51,750 232,605 20,642 211,963 49.1 Output constrained by transmission limits May 744 195,535 73,040 268,575 21,681 246,894 55.3 Jun 720 71,590 197,762 269,352 20,432 248,920 57.6 Jul 744 0 177,215 177,215 12,864 164,351 36.8 Final Inspection-Unit 1 Aug 744 45,800 195,080 240,880 17,839 223,041 50.0 Unit 1 Failure/Repair Sep 720 0 191,180 191,180 13,490 177,690 41.1 Unit 1 Repair Oct 744 0 163,975 163,975 11,322 152,653 34.2 Unit 1 Repair Nov 720 0 0 0 0 0 0.0 Unit 1 Repair/Unit 2 maintenance (annual)Dec 744 10,109 0 10,109 1,825 8,284 1.9 Unit 1 Repair/Unit 2 maintenance (annual) 8,760 646,859 1,446,842 2,093,701 157,985 1,935,716 36.8 2000 Jan 744 167,224 0 167,224 13,667 153,557 34.4 Unit 2 Failure/Repairs Feb 696 217,139 0 217,139 15,029 202,110 48.4 Unit 2 Failure/Repairs Mar 744 205,438 0 205,438 13,707 191,731 43.0 Unit 2 Failure/Repairs Apr 720 198,653 0 198,653 13,769 184,884 42.8 Unit 2 Failure/Repairs May 744 65,228 0 65,228 5,640 59,588 13.3 Unit 2 Failure/Repairs Jun 720 168,695 108,278 276,973 22,718 254,255 58.9 Jul 744 144,879 190,554 335,433 24,849 310,584 69.6 Aug 744 172,277 217,211 389,488 27,755 361,733 81.0 Sep 720 169,552 217,974 387,526 27,393 360,133 83.4 Oct 744 144,461 195,054 339,515 25,244 314,271 70.4 Nov 720 0 180,459 180,459 13,713 166,746 38.6 Unit 1 Maintenance (annual) Dec 744 107,655 207,961 315,616 21,654 293,962 65.9 Unit 1 Maintenance (annual) 8,784 1,761,201 1,317,491 3,078,692 225,138 2,853,554 54.1 MWh = megawatt-hour. a Based on actual figures until April 2001 and estimated at 7.1% of gross generation afterwards. b Based on net output at 230 kilovolt. Source: Masinloc Thermal Power Plant.

22 Appendix 3

GENERATION OUTPUT DATA FOR MASINLOC THERMAL POWER PLANT (Contd.)

Auxiliary Net Plant Year/ Gross Generation (MWh) Usea Output Factorb Month Hours Unit 1 Unit 2 Plant (MWh) (MWh) (%) Remarks 2001 Jan 744 195,446 176,368 371,814 26,251 345,563 77.4 Feb 672 184,903 207,826 392,729 26,968 365,761 90.7 Mar 744 193,637 194,548 388,185 25,766 362,419 81.2 Apr 720 213,160 208,855 422,015 28,069 393,946 91.2 May 744 211,212 211,796 423,008 30,034 392,974 88.0 Jun 720 222,208 141,831 364,039 25,847 338,192 78.3 Jul 744 165,431 69,165 234,596 16,656 217,940 48.8 Unit 2 Maintenance Aug 744 111,565 212,013 323,578 22,974 300,604 67.3 Sep 720 75,576 218,964 294,540 20,912 273,628 63.3 Oct 744 108,126 187,240 295,366 20,971 274,395 61.5 Nov 720 80,777 195,813 276,590 19,638 256,952 59.5 Dec 744 0 186,833 186,833 13,265 173,568 38.9 Unit 1 Maintenance (annual) 8,760 1,762,041 2,211,252 3,973,293 277,351 3,695,942 70.3 2002 Jan 744 165,565 116,036 281,601 19,994 261,607 58.6 Feb 672 189,705 190,671 380,376 27,007 353,369 87.6 Mar 744 166,124 167,445 333,569 23,683 309,886 69.4 Apr 720 197,910 203,446 401,356 28,496 372,860 86.3 2,880 719,304 677,598 1,396,902 99,180 1,297,722 75.1 MWh = megawatt-hour. a Based on actual figures until April 2001 and estimated at 7.1% of gross generation afterwards. b Based on net output at 230 kilovolt. Source: Masinloc Thermal Power Plant.

UNIT OUTAGE/AVAILABILITY FOR MASINLOC THERMAL POWER PLANT 1999 2000 2001 2002 Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2 Unit 1 Unit 2

Outage Availability Outage Availability Outage Availability Outage Availability Outage Availability Outage Availability Outage Availability Outage Availability Month Hoursa (h) (%) (h) (%) (h) (%) (h) (%) (h) (%) (h) (%) (h) (%) (h) (%) Jan 744 495 34 234 69 114 85 744 0 0 100 67 91 78 90 251 66 Feb 672 365 46 161 76 0 100 672 0 61 91 0 100 0 100 0 100 Mar 744 590 21 73 90 0 100 696 6 0 100 0 100 2 100 0 100 Apr 720 0 100 473 34 53 93 720 0 0 100 34 95 0 100 0 100 May 744 24 97 303 59 403 46 744 0 0 100 0 100 Jun 720 501 30 0 100 0 100 258 64 0 100 255 65 Jul 744 744 0 27 96 63 92 0 100 35 95 425 43 Aug 744 554 26 19 98 0 100 0 100 0 100 0 100 Sep 720 720 0 50 93 0 100 0 100 230 68 0 100 Oct 744 744 0 141 81 65 91 19 97 0 100 52 93 Nov 720 720 0 720 0 720 0 32 96 290 60 15 98 Dec 744 602 19 744 0 304 59 0 100 744 0 0 100 Total 8,760 6,058 31 2,943 66 1,721 80 3,884 56 1,360 84 847 90 80 99 251 97 h = hours. a Total number of hours for 1999 and 2001 was 8,760 as shown here, but was 8,784 for 2000. The additional February hours in 2000 were not considered in the calculation. Source: Masinloc Thermal Power Plant.

24 Appendix 5

COMPLIANCE WITH MAJOR LOAN COVENANTS Covenant Status 1. Provision of adequate local funds for the Project. Reference: LA 1042; Section 4.02

Complied with.

2. Submission of annual financial statements audited by auditors acceptable to ADB, not later than 6 months after the end of each fiscal year.

Reference: LA 1042; Section 4.12

Complied with.

3. Self-financing ratio, on a 3-year moving average basis, of not less than 20%.

Reference: LA 1042; Section 4.12

Detailed data unavailable, but compliance indicated.

4. Debt service ratio of at least 1.0 in 1996 and 1997 and 1.3 times from 1998 onwards.

Reference: LA 1042; Section 4.13

Not complied with. The ratio was 0.9, 0.7, and 1.0 for 1999, 2000, and 2001, respectively.

5. Rate of return on average net revalued fixed assets in operation of at least 8%.

Reference: LA 1042; Section 4.14

Not complied with. The rate was 3.4, 2.2, and 2.9 for 1999, 2000, and 2001, respectively.

6. Accounts receivable of no more than the equivalent of 3 months’ sales.

Reference: LA 1042; Section 4.15

Complied with.

7. Annual discussion with ADB of the results of tariff reviews and the proposed measures to maintain the tariffs at adequate levels.

Reference: LA 1042; Schedule 6, para. 3 (b)

Complied with.

8. Annual submission of the National Power Corporation 3-year budget, together with the corresponding financial projections and power expansion program.

Reference: LA 1042; Schedule 6, para. 4

Complied with.

9. Revaluation of assets by independent appraiser as of 31 December 1992 and every 4-years thereafter.

Reference: LA 1042; Schedule 6, para. 6

Not fully complied with. No independent appraisal undertaken in 2000, but waiver requested from ADB.

10. Development of computerized accounting system and audit to be continued.

Reference: LA 1042; Schedule 6, para. 7

Complied with.

11. Approval of the Project by the Environmental Management Bureau in the Department of Environment and Natural Resources, and implementation, operation and maintenance of the Project in a manner minimizing environmental damage and consistent with the laws and legal environmental requirements.

Reference: LA 1042; Schedule 6, para. 10

Complied with.

12. All lands, properties, rights-of-way, easements, licenses, and other rights or privileges that may be necessary to enable the carrying out of the Project to be acquired or made available in sufficient time to avoid delay in the implementation of the Project.

Reference: LA 1042; Schedule 6, para. 11

Not complied with. Protracted acquisition of land and rights-of-way caused major implementation delays.

13. Sufficient and timely supply of required quality of coal is continuous to enable the project facilities to operate at the level of generation intended.

Reference: LA 1042; Schedule 6, para. 12

Complied with.

14. Completion of the 230 kV transmission line from Masinloc to Hermosa via Botolan together with the required terminal facilities prior to the commissioning of the first 300 MW unit to be constructed under the Project to enable the immediate operation of the project facilities.

Reference: LA 1042; Schedule 6, para. 14

Partly complied with. The original design changed due to the eruption of Mt. Pinatubo. The new design implemented with minor delay.

ADB = Asian Development Bank, LA = Loan Agreement, kV = kilovolt, MW = megawatt. Source: Operations Evaluation Mission.

Appendix 6 25

REEVALUATION OF FINANCIAL AND ECONOMIC INTERNAL RATES OF RETURN

A. General 1. The financial and economic reevaluation of the Project was carried out in terms of with- and without-project scenarios. All prices and costs were expressed in the second quarter 2002 constant Philippine peso values. The costs and benefits incurred before 2002 were adjusted using the Philippine consumer price index. The reevaluation was carried out for combined units 1 and 2 of Masinloc Thermal Power Plant (MTPP) as they had identical design, were functionally inseparable and more or less commissioned at the same time, and shared all auxiliary components. A 30-year operating life was assumed for MTPP. B. Financial Internal Rate of Return 2. Although the Project did not have transmission and distribution components, estimating the financial internal rate of return (FIRR) included an allocation of costs for the necessary transmission facilities to deliver the generated energy to the wholesale level. For the capital expenditure for the two units and transmission lines, the estimates used in the project completion report (PCR) for Loan 1398-PHI: Northern Luzon Transmission and Generation Project were used. Specifically, the capital expenditures included (i) 100% of the costs of MTPP completion, (ii) 100% of the Masinloc to Labrador 230-kilovolt (kV) transmission line, (iii) 33% of the cost of the Labrador to San Jose 500 kV transmission line, and (iv) 33% of the cost of the associated substations. Assumptions (iii) and (iv) were based on the fact that the substation and the transmission lines were jointly used by MTPP and the Sual Plant. Interest paid during construction was deducted from the calculation. Additional assumptions were made based on information obtained by the Operations Evaluation Mission (OEM): (i) average fuel costs of P0.60/kilowatt-hour (kWh) of gross generation (estimated from current actual coal prices); (ii) annual operation and maintenance (O&M) costs of P0.10/kWh of MTPP and 2% of the allocated capital costs of the transmission and substations; (iii) annual sales of 3,739 gigawatt-hours (GWh)1 to the Luzon grid based on a net generation of 3,915 GWh2 and transmission losses of 4.5%; and (iv) an average wholesale tariff of P2.34/kWh for 1998 and P2.89/kWh for 1999 and subsequent years.3 3. Based on these assumptions, the recalculated FIRR is 21.4% (see Table A6.1), substantially above the weighted average cost of capital of 6.3% for the Project.4

1 Generation projections for 2002 and 2003 were reduced to account for the decreased availability resulting from the

75 days outage of one unit each year for the required fifth year overhaul. Projected generation for the remaining years assumes a 40-day maintenance outage for each unit.

2 Gross generation of 4,189 GWh with auxiliary use at 6.5%. 3 Base rate plus foreign exchange and fuel adjustments, but excluding the power purchasing agreement adjustment

passed on to the independent power producers (IPPs). 4 The weighted average cost of capital represents the cost incurred by the borrower in raising the capital necessary

to implement a project. NPC’s traditional sources of capital were used in the calculation, including foreign loans (73%), issuance of NPC bonds (24%), and domestic commercial sources (3%).

26 Appendix 6

C. Economic Internal Rate of Return 4. To convert financial costs to economic costs, all taxes and duties were deducted. Nontradable costs of local goods and services, which were estimated as about 20% of total financial costs, were converted to border prices using a 0.88 standard conversion factor. In addition to the transmission costs, as included in the financial reevaluation, the economic reevaluation also included the average distribution cost, estimated at P1.75/kWh, and distribution losses estimated at 14%. 5. The economic benefits of the Project to society were attributed to two sources: (i) resource savings from replacing existing but more expensive generation option, namely, oil-based generation units; and (ii) economic value of additional electricity sales. Although part of the rationale for the Project was to replace the existing oil-based units in Luzon, its delayed completion has reduced the first category of benefits attributable to switching from oil to coal. Most of the oil-based units continued to operate till January 2000 when they were decommissioned at the average age of about 30 years. Even without MTPP, those aging oil-based plants would have to be retired soon. Therefore, the substitution benefit is assumed to be minimal and all electricity generated and sold by MTPP is for additional uses, whose benefit may be estimated using the average willingness-to-pay (WTP) approach.5 6. To estimate WTP, a linear demand function for electricity was assumed for all electricity consumers in Luzon (Figure A6). The linear demand function assumes that there exists a maximum consumption level, qmax, when the price reaches zero (i.e., the demand is not infinite at zero price). Likewise, there exists a maximum price, pmax, beyond which the consumption of electricity would be zero (i.e., all customers would switch to alternatives such as self-generation). The quantities of electricity generated and sold for the with- and without-project scenarios are denoted by qw and qwo with their corresponding demand prices pw and pwo. The economic benefit of the incremental quantity (qwo – qw) is the area beneath the demand curve between qwo and qw. 7. To determine the slope of the linear demand function, two points are needed. The current actual price and total electricity consumption in Luzon, i.e., with-project, were used as the first point (qw, pw). Information provided by the National Power Corporation (NPC), Manila Electric Company (Meralco), and representatives of smaller utility cooperatives in northern Luzon indicates that, in 2001, total actual sales of electricity in Luzon or qw was 24,073 GWh, while the weighted average actual retail price for Luzon or pw was P6.46/kWh.6 To estimate the second point (p2, q2), one needs to estimate the feasibility and costs of self-generation as an alternative for customers with different capacity demands. Table A6.2 provides cost estimates for diesel generators of various capacities, which can meet most industrial and commercial customers’ demand. It indicates that the resulting cost is about P5/kWh for most generators. Considering the additional cost of land and other barriers to a consumer procuring and installing a generating system for internal use, i.e., initial capital costs, reluctance to enter into an “alternative business”, concerns as to future fuel costs, O&M considerations, competing demands for capital, etc., the actual price that would trigger the switch to self-generation is likely to be much higher than P5/kWh. In a customer survey conducted by Meralco, many customers 5 This approach is based on the fact that MTPP has been used to meet the base load, and other generation

capacities from IPPs did not exist at the time of appraisal, i.e., under the without-project scenario. According to MTPP officials, IPPs also have higher generation costs.

6 Average retail tariff for Meralco customers was P6.53/kWh, while the retail price for a small utility cooperative near MTPP was P5.87/kWh.

Appendix 6 27

indicated that they would be willing to stay with Meralco as long as the price is not more than 15% higher than what they are paying now, averaged at P6.46/kWh.

Figure A6: Demand Curve for Electricity 8. The OEM believes that users with a combination of high load factor and whose overhead and production costs are electricity-intensive are more likely to start a self-generation to avoid increasing costs from the utility supply. Examples are ice plants, refineries, and cement producers. Many of these enterprises exhibit load factors of 50% and more. Assuming an increase in price of about 15% or P1/kWh to P7.46/kWh, the OEM estimates that a total demand of 700 megawatts (MW) of load presently connected to the Luzon grid, which has a total available capacity of 5,300 MW, is likely to induce a move to self-generation. This is equivalent to 3,066 GWh for the Luzon grid. Therefore, total electricity sale for Luzon or q2 when the retail price p2 reaches P7.46/kWh is estimated as 24,073 – 3,066 = 21,007 GWh (about 13% reduction in electricity consumption). 9. Using the linear demand function defined by the above two points, it is possible to determine the marginal demand price or marginal WTP given a level of electricity sale. For the without-project scenario, total electricity sale in Luzon qwo in 2001 would have been total actual electricity sale minus electricity sale by MTPP for the year, or 24,073 GWh – 3,177 GWh = 20,896 GWh. The marginal demand price for the without-project scenario or pwo is calculated as P7.50/kWh. The average WTP for Luzon industrial, institutional, and residential customers is thus calculated as (pw + pwo)/2 or P6.98/kWh.7 On this basis, the economic internal rate of return is estimated at 29.7% (Table A6.3).

7 Using the same information but a nonlinear demand function, as adopted by the Economic Research Department’s

Technical Note No. 3: Measuring Willingness to Pay for Electricity, would give a higher average WTP estimate.

qmax q qw

p

pmax

pw

0

pwo p2

qwo q2

Average Willingness-to-Pay

Table A6.1: Financial Internal Rate of Return (Costs and Revenues in P million in 2002 Prices)

Capital Costs Masinloc Transmission Operating Costs Total Generation Sales Net Cash Year Units 1 & 2 230 kV & 500 kV Substations Fuel O&M Costs (GWh) Revenues Flow 1994 1,898.43 1,898.43 (1,898.43)1995 390.98 390.98 (390.98)1996 2,961.50 323.62 190.22 3,475.34 (3,475.34)1997 8,461.61 896.24 526.81 9,884.65 (9,884.65)1998 7,330.06 1,098.45 645.68 616.45 162.49 9,853.13 960.20 916.99 2,376.64 (7,476.48)1999 1,379.97 314.06 184.60 1,242.73 269.04 3,390.41 1,935.72 1,848.61 5,917.34 2,526.93 2000 1,455.19 450.01 264.52 1,831.98 373.73 4,375.42 2,853.55 2,725.14 8,723.08 4,347.66 2001 2,372.79 457.97 2,830.76 3,695.94 3,529.62 11,298.20 8,467.43 2002 2,302.03 446.95 2,748.97 3,585.71 3,424.35 9,896.38 7,147.41 2003 2,302.03 446.95 2,748.97 3,585.71 3,424.35 9,896.38 7,147.41 2004 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2005 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2006 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2007 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2008 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2009 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2010 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2011 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2012 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2013 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2014 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2015 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2016 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2017 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2018 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2019 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2020 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2021 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2022 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2023 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2024 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2025 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2026 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2027 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 2028 2,513.65 479.91 2,993.56 3,915.35 3,739.16 10,806.17 7,812.61 FIRR = 21.4%FIRR = financial internal rate of return, GWh = gigawatt-hour, kV = kilovolt, O&M = operation and maintenance. Source: Operations Evaluation Mission.

Appendix 6 29

Table A6.2: Unit Costs of Generation in the Philippines, 2002

P/$ = 50.00Item Type 1 Type 2 Type 2 Type 3 Type 4 Load Demand (kW) 1,000 1,000 1,000 5,000 10,000Power Factor >0.90 >0.90 >0.90 >0.90 >0.90Unit Configuration 2 x 500 2 x 500 2 x 500 5 x 1,000 5 x 2,000$/kW Installed 225 225 225 150 125Total $ 225,000 225,000 225,000 750,000 1,250,000 Total P 11,250,000 11,250,000 11,250,000 37,500,000 62,500,000 Load Factor 65% 60% 50% 50% 50%Annual kWh 5,694,000 5,256,000 4,380,000 21,900,000 43,800,000 Fuel Usage (liter) 1,898,000 1,752,000 1,460,000 7,300,000 14,600,000 Fuel Cost/liter (P) 13 13 13 13 13 Fuel Cost (P) 24,863,800 22,951,200 19,126,000 95,630,000 191,260,000 Debt Service (P) over 10 yr 1,830,881 1,830,881 1,830,881 6,102,938 10,171,563 O&M (P) 1,000,000 1,000,000 1,000,000 5,000,000 10,000,000 Total Cost (Annual) 27,694,681 25,782,081 21,956,881 106,732,938 211,431,563 P/kWh 4.86 4.91 5.01 4.87 4.83 kW = kilowatt, kWh = kilowatt-hour, O&M = operation and maintenance, P = Philipinne peso. Assumptions: 1. Generation is by diesel-driven generator. 2. Diesel as fuel, fuel efficiency at 3.0 kWh/liter. 3. "Slow-speed" units utilized for base load generation (typical rated rpm at 600, 1,200, 1,800). 4. Power Factor < 0.90 corrected by capacitors. 5. Installation considered as "temporary" due to 5-10 years expected high rates due to purchase power

adjustment. Notes: 1. Above assumes no cost of land, no extraordinary maintenance, levelized fuel costs. 2. Similar installations in the United States normally provide generation at $0.06–0.08/kWh. Source: Operations Evaluation Mission.

Table 6.3: Economic Internal Rate of Return (Costs and Revenues in P million in 2002 Prices)

Capital Costs Wholesale Retail Net Masinloc Transmission Operating Costs Distribution Total Generation Sales Sales Economic Economic Year Units 1 & 2 230 kV & 500 kV Substations Fuel O&M Cost Costs (GWh) (GWh) (GWh) Benefits Benefits 1994 1,579.49 1,579.49 (1,579.49)1995 325.30 325.30 (325.30)1996 2,463.97 269.25 158.26 2,891.48 (2,891.48)1997 7,040.06 745.67 438.30 8,224.03 (8,224.03)1998 6,098.61 913.91 537.20 616.45 1,604.73 9,913.90 960.20 916.99 788.61 4,843.97 (5,069.93)1999 1,148.13 261.30 153.59 1,242.73 236.76 3,235.07 6,277.59 1,935.72 1,848.61 1,589.81 9,765.23 3,487.64 2000 1,210.72 374.41 220.08 1,831.98 328.88 4,769.00 8,735.06 2,853.55 2,725.14 2,343.62 14,395.46 5,660.40 2001 2,372.79 403.01 6,176.84 8,952.65 3,695.94 3,529.62 3,035.48 18,645.10 9,692.46 2002 2,302.03 393.31 5,992.62 8,687.96 3,585.71 3,424.35 2,944.94 18,089.02 9,401.07 2003 2,302.03 393.31 5,992.62 8,687.96 3,585.71 3,424.35 2,944.94 18,089.02 9,401.07 2004 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2005 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2006 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2007 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2008 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2009 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2010 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2011 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2012 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2013 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2014 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2015 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2016 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2017 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2018 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2019 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2020 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2021 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2022 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2023 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2024 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2025 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2026 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2027 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 2028 2,513.65 422.32 6,543.53 9,479.50 3,915.35 3,739.16 3,215.68 19,751.97 10,272.47 EIRR = 29.7% EIRR = economic internal rate of return, GWh = gigawatt-hour, kV = kilovolt, O&M = operation and maintenance. Source: Operations Evaluation Mission.

Appendix 7 31

RESETTLEMENT AND SOCIAL IMPACT EVALUATION A. Introduction 1. Before the construction of the 600 megawatt Masinloc Thermal Power Project (MTPP) in Zambales Province in the Philippines, the National Power Corporation (NPC) developed a resettlement program with a budget of P73.4 million. The relocation of 198 project-affected families (PAFs)—about 1,000 persons—was completed in June 1996, about 2 years before the commissioning of MTPP. 2. The Operations Evaluation Mission (OEM) (i) reviewed the resettlement program and examined in detail the three compensation options and the two livelihood programs for the PAFs as to fairness and long-term sustainability, and identified key weaknesses and problems; (ii) discussed the implementation of the resettlement program with NPC and assessed the current status of the PAFs in terms of compensation and other payments; (iii) inspected the relocation site and facilities and interviewed persons from 51 PAFs; (iv) assessed the effectiveness of the livelihood programs, with due attention to problems encountered during implementation; (v) identified key lessons that can be learned from the design and implementation of the resettlement program; and (vi) recommended to NPC and the Government measures to monitor the PAFs’ livelihood and to continue providing them with the necessary assistance. 3. With assistance from MTPP, the OEM chose the respondents according to their settlement clusters, compensation options, and gender and age. The persons interviewed were among the beneficiaries of the resettlement program developed by the Social Engineering Department (SED) of NPC in 1993.1 Of the total persons interviewed, 21 came from PAFs who availed of a house and a lot, 3 from those who opted for the cash equivalent of a house and a lot in the resettlement site, and 27 from those who chose self-relocation with cash compensation for a lot and a house (Table A7.1). The respondents were 35 males and 16 females in all age groups. Of the persons interviewed, 17 (33%) had elementary education, 26 (51%) had studied in high school, 4 (8%) in college, and 4 (8%) had vocational training. The size of PAFs ranged from 1 to 11 members, averaging 5.2 persons per family. B. Operations Evaluation Mission Findings

1. Resettlement Program 4. The resettlement program lacked information on some essential inputs for social planning and income restoration, such as summary of damages to properties, classification of PAFs as to type of damages, eligibility and entitlement criteria, and socioeconomic characteristics of PAFs. The legal basis of NPC in computing compensation had not been explained. It was not clear if an environmental impact study (EIS) of the 6.6-hectare relocation site was conducted or was integrated with the EIS of MTPP. For a resettlement site envisaged as home to about 200 PAFs, environmental viability is important.

1 At the time, the Asian Development Bank had yet to develop its policy on resettlement. R179-95. Involuntary

Resettlement was issued in September 1995. Although the World Bank’s policy was formulated in 1990, preparing resettlement action plans was not yet practiced in the Philippines.

32 Appendix 7

2. Implementation

a. Accomplishment of Resettlement Objectives 5. NPC successfully achieved the first objective—to relocate the PAFs within the boundaries of the project site after they had been compensated. The PAFs were divided into two groups. The first group was composed of 105 PAFs who were relocated at a resettlement site in Barangay Taltal, 1.5 kilometers (km) away from their original settlement. The second group, consisting of 93 PAFs, opted for self-relocation in Purok Pag-asa and Little Baguio adjacent to the gate of MTPP. 6. The second objective—to develop a resettlement program that would be socially and economically acceptable to PAFs—was substantially achieved. NPC provided modest facilities at the resettlement site. The site has a concrete school building for complete elementary grades for which the local government will hire additional teachers this school year. The residential structures are bigger and better than the low-cost housing units provided under the housing program of the Government. Although the PAFs outside do not enjoy some of the amenities in the resettlement site, NPC paid cash compensation allowing them to buy residential lots and build their houses at the time. Those PAFs could also raise domestic animals or plant vegetables in their backyard. All these achievements are not to suggest that the resettlement program is problem free. There still are a number of outstanding issues to be resolved. On the whole, however, despite the lack of a clear policy guidance regarding resettlement from both the Asian Development Bank (ADB) and the Government at the time of project formulation and during implementation, the resettlement program as implemented appears to be socially and economically acceptable to PAFs. 7. From 1993 to 1998, NPC extended financial assistance to socioeconomic projects sponsored by the provincial government of Zambales, the local government unit of Masinloc, and the barangays of Bani and Taltal. The total assistance amounted to P324.8 million, including the projects stipulated in the multipartite memorandum of agreement (MOA). The second objective would have been completely achieved had there not been some environmental concerns at the resettlement site, which is vulnerable to flood and soil erosion. This situation at times has affected its sanitary conditions. Another problem is the lack of drinkable water after earthquake damaged the well that NPC provided. Households have installed their own deep wells, but are extracting water with high salinity. As a result, they have to purchase or acquire water from other sources. 8. NPC has not fully met the third objective—to define the responsibilities of NPC offices and the PAFs in planning, implementing, monitoring, and evaluating the resettlement program. SED did not coordinate with MTPP management on the information it disseminated to PAFs. NPC has no permanent community relations officer in MTPP. Finally, SED had excluded the PAFs outside the resettlement site from the monitoring and assistance in livelihood programs.

b. The Three Compensation Options 9. Generally, the three compensation options provided by NPC compare favorably with compensation paid by other government agencies. However, despite the relative merit of the options, the PAFs may not have understood the legal basis during negotiations. NPC’s resettlement program was referring to Executive Order 1035, and the PAFs to Republic Act No. 3844. The latter was perceived as more advantageous to the PAFs’ interests. Partly because of the confusion, a group of PAFs filed a case claiming more compensation against MTPP management, and this received a favorable ruling from the court. NPC has filed for reconsideration, which is being reviewed by the Court of Appeals.

Appendix 7 33

10. After 6 years, the 86 PAFs that received compensation under the first option, i.e., a house and lot, are now reduced to 63 and some of these are considering leaving the resettlement site for various reasons. The OEM found that (i) 14 PAFs had already sold their residential units at a price much higher than the compensation they received,2 and the new owners have already made improvements; (ii) 4 units are occupied by relatives of PAFs; and (iii) 5 are rented to outsiders. A few others who sold their units are now squatting on NPC reserved lands. Seven of the 19 PAFs who took the second option, i.e., cash compensation for their house and a lot at the resettlement site, are now living outside the resettlement site. They sold their lots and the proceeds were used for starting a business. Some of the 93 PAFs who chose the third option, i.e., living outside the resettlement area with cash compensation, used their compensation in buying residential lots, leaving an insufficient amount for house construction. Joblessness is their main concern. 11. Already behind schedule, as per the resettlement program, NPC has not yet awarded to PAFs the title of property ownership in the resettlement area. The MTPP management is still working to transfer land titles from the former owner of the land to PAFs through NPC.

c. The Livelihood Programs 12. Two livelihood programs provided by NPC had different outcomes. The Municipal Cooperative Development Office (MCDO) under the office of the municipal mayor has efficiently administered the P10.0 million livelihood program for the beneficiary residents of Masinloc. From 333 client members in 1999, the number has grown to 617. The success of the members is primarily attributable to their access to a large number of customers and lower operating cost of their businesses such as tricycle/jeepney operation and variety stores. MCDO now has more than P19.0 million available for lending to client members. 13. The Samahang Pagkakaisa ng mga Relocatees ng Bani (SPRB), the association formed by PAFs at the resettlement site that administered the P1.86 million livelihood fund, has ceased operation due to collection problems. The causes of its failure, as viewed by the MCDO manager, were as follows: (i) priority of loan releases to relatives of SPRB officers; and (ii) the members, except one who had fully paid her loan, were not paying their dues because the officers were not doing so. The OEM was informed that SPRB was hastily organized and members were not trained in entrepreneurship. SPRB has no more funds. Its failure is reflected in unsuccessful livelihood projects implemented by its members, such as fishing, tricycle/jeepney operation, and variety stores. Loan repayment difficulties also reflected large family size, resulting in spending to meet basic necessities as a priority. C. Overall Socioeconomic Impacts

14. The OEM grouped the responses of the PAFs to gauge the overall socioeconomic impacts of relocation: 24 respondents (47%) complained of income declines, 4 (8%) indicated an income increase, and 23 (45%) did not respond (Table A7.2). Among the 24 persons who experienced income decline, 21 were former tenant farmers and 3 were previous landowners whose agricultural lands were expropriated by NPC. The rest of the respondents were 13 fishermen and 14 persons of varied occupations whose livelihoods tended to be influenced by other external factors.

2 The selling price of a house and lot is P150,000–P200,000, compared with the P107,000 compensation received

from NPC.

34 Appendix 7

15. The adversely affected tenant farmers indicated an average decrease of 57% in earnings. However, the decrease was being offset by the contribution of young adult members of the households whose income was not indicated in the survey. Other families indicating decreased income also had young adult working members, some of whom graduated from college after relocation. Notwithstanding the significance of the income decline for some PAFs, it should be pointed out that nearly half of the respondents did not answer the question on change in income and, for those who indicated an income decline, there existed a positive incentive to report income loss in the hope of more compensation from NPC, especially in light of the ongoing lawsuit. It would also be inappropriate to attribute all the income loss to resettlement, considering the general deterioration of macroeconomic conditions after the Asian financial crisis. On the whole, the OEM observed that most PAFs that NPC relocated 6 years ago had already recovered from social displacement. D. Conclusions and Recommendations

1. Conclusions 16. Despite several outstanding issues related to the compensation amounts, economic opportunities for the PAFs, delayed transfer of land titles, and environmental concerns at the resettlement site, NPC has either fully or partly met the objectives of the resettlement program with some limitations. In the OEM’s view, the PAFs were generally fairly compensated and relocated in areas close to their previous settlements. Many resettlers have already rehabilitated themselves. However, the aforementioned issues have yet to be fully addressed. In the short term, NPC needs to address the implications of the case filed against MTPP management. The case is under appeal, but it could be a deterrent to potential investors in the ongoing privatization of the Philippine power sector.

2. Lessons Learned

a. National Power Corporation 17. First, considering the large number of PAFs in the proposed site of MTPP, NPC should have appointed a full-time community organization and relations officer to assist in social preparation. Adequate preparation could have minimized the adverse impacts of transition and may have prevented the PAFs from filing a case against MTPP management had they been properly informed. Second, the resettlement program of NPC in Barangay Bani should have been prepared by a team with members of diverse disciplines. Third, given the terrain and location of the resettlement site in Sitio Togue, Barangay Taltal, a separate EIS should have been conducted or integrated with the EIS for MTPP. Fourth, SED should have conducted feasibility studies on the livelihood programs proposed for the PAFs and assigned a community organization and relations officer for assistance in implementation. Finally, SED should have considered the social characteristics, including the talents and skills, of the PAFs before implementing the livelihood programs. In short, resettlement should be based on a time-bound action plan of documented measures, be founded on a sound legal basis and a cogent assessment of the pre-project socioeconomic situation, and be fully and clearly communicated to all PAFs. This would allow a clear comparison of what was intended and what was actually achieved after resettlement.

b. Asian Development Bank 18. Although ADB did not have an official policy on involuntary resettlement at the time of project formulation, such a policy was issued in 1995 (footnote 1) and became effective during

Appendix 7 35

project implementation. ADB should have provided more supervision on resettlement issues during project implementation. The experience of the OEM also validates the strong need to conduct monitoring on resettlement during and after program implementation.

3. Follow-Up Actions and Recommendations

a. Concerns at Resettlement Sites 19. To mitigate the social concerns of the resettlers, NPC first needs to arrange with the local government of Masinloc and the barangay governments of Bani and Taltal to provide water lines. NPC should help them prepare the required documents to access financial benefits under Energy Regulations No. 1-94 implementing Section 5(i) of Republic Act No. 7638. NPC should encourage the local governments to share the cost, from its annual investment development plan, in financing the water lines for the PAFs. Second, NPC should try to resolve the ongoing lawsuit in a mutually satisfactory and forward-looking manner, as it may potentially impede the pace of the scheduled privatization. Six years after the resettlement, the land titles still have not been transferred to the PAFs. NPC should take immediate steps to resolve this issue. Third, as the local economy of Masinloc is concentrated in the public market, which is about 8 km from Barangay Bani and Taltal, the NPC should study the feasibility of constructing a basic market near Barangay Bani where there is a large number of consumers. The market would benefit the local community, particularly the PAFs, by providing more economic opportunities for them. MCDO may provide the loan fund, but it should not appear as free money from NPC or the Government. All the recommended measures should be completed before NPC’s privatization scheduled in the second half of 2003.

b. General Recommendations 20. Drawn from the MTPP experience, the following general measures are recommended. First, NPC should strengthen its internal monitoring and appoint, on a long-term basis, an adequate number of project-based community organization and relations officers who can immerse themselves in the communities holding the right-of-way in NPC’s future projects. The immersion will provide information on personal aspirations of the PAFs that could enhance the planning, monitoring, and evaluation of resettlement programs. Second, NPC should appoint an independent institution to monitor the implementation of resettlement programs for its projects so that the planned activities are efficiently executed, PAFs are fairly compensated, and their social rehabilitation is sustained. Third, NPC should treat the PAFs as social development clients and each PAF should be assigned a card that will be maintained by the external monitoring institution. The card will indicate the socioeconomic benchmarks for monitoring during the period of rehabilitation. These measures may be implemented over a longer period, e.g., in the next 3 years, by NPC-derived entities (after privatization). 21. The experience of MTPP highlights the need for the Government to develop an involuntary resettlement policy that will address compensation at replacement cost, livelihood programs, and other issues involved. A draft executive order on this subject, which is an output of ADB technical assistance,3 is being finalized by various government agencies. It is important that the Government approve the policy at the earliest to minimize costly project delays and ensure fair and socially responsible compensation and livelihood programs for would-be-affected persons.

3 TA 5935-REG: National Resettlement Policy Enhancement and Capacity Building, for $500,000, approved on

20 September 2000.

36 Appendix 7

Table A7.1: Sampling Scheme

Resettlement Option

Number

of PAFs

Number of PAF Representatives

Interviewed

Share in

Total (%)

Option 1: House and Lot at Resettlement Site

86 21 41.1

Option 2: Lot at Resettlement

Site and Cash Compensation for House

19 3 5.9

Option 3: Cash Compensation for House and Lot

93 27 53.0

Total 198 51 100.0 PAF = project-affected family.

Table A7.2: Income Analysis of Project-Affected Families Before and After Relocation

Respondent

Occupation Before and After Relocation Yearly Income Before and

After Relocation (P)

No. Age Before After Before After Change Remarks 1. 48 Fishing Fishing 31,200 15,600 (15,600) Has two college graduate children 2. 41 Farming/Fishing Fishing 60,000 31,200 ( 28,800) Directly affected–but with multiskills 3. 55 Fishing None 36,000 12,000 ( 24,000) Widowed; supported by children 4. 53 Farming/Fishing Village Police 62,400 18,000 ( 44,400) Directly affected–skill in driving, assisted by child 5. 49 Dressmaking Dressmaking — — — Directly affected–widower 6. 56 Farming/Fishing None 38,400 24,000 ( 14,400) Directly affected–wife accepting laundry 7. 60 Farming/Fishing Wood Gathering — — — Directly affected 8. 87 Landowner None 1,800,000 0 (1,800,000) Directly affected–loss of income from agricultural land 9. 41 Small Variety

Store Heavy Equipment Operator

72,800 — — Directly affected, but potentially increased income

10. 57 Farming None 720,000 180,000 ( 540,000) Directly affected, but has small business and assistance

11. 34 Waiter Security Guard — — — With small business and using his multiskills. 12. 31 Fishing Heavy Equipment

Operator 62,400 68,952 6,552 Employed

13. 42 Small Variety Store

Small Variety Store 182,000 364,000 182,000 Husband employed as policeman

14. 83 Farming/Carpentry None 46,800 0 ( 46,800) Directly affected and old age 15. 28 Carpentry Carpentry 78,000 — — Practicing the skills 16. 33 Varied None 72,000 — — Directly affected but practicing multiskills 17. 52 Farmer/Laborer None 39,000 — — Directly affected but w/ knowledge in drafting 18. 45 Farming Farming 31,200 31,200 0 Retained income with knowledge in driving 19. 32 Farming/Fishing None 31,200 — — Directly affected but with knowledge in driving 20. 32 Jeepney Driving Maintenance Guard 78,000 37,440 ( 40,560) With knowledge in driving, house painting 21. 63 Fishing Fishing 31,200 0 ( 31,200) Disabled; supported by adopted child 22. 38 Small Variety

Store None 312,000 0 ( 312,000) Husband driving a public utility vehicle

23. 87 Landowner Landowner 174,816 405,600 230,784 Senior citizen with support from children in the United States of America

24. 32 Fishing Driving 104,000 130,000 26,000 Also works as mechanic, house painter, carpenter 25. 66 Farming Vegetable Vending — — — Directly affected, widowed but shifted to vending 26. 40 Farming/Fishing None 62,400 — — Directly affected; former the National Power

Corporation security guard 27. 54 Farming/Fishing None 46,800 — — Directly affected but with adult children working 28. 46 Fishing Driving 62,400 31,200 ( 31,200) With knowledge in carpentry, electricity technician 29. 70 Farming/Fishing None 62,400 0 ( 62,400) Directly affected, old age, with sons able to work 30. 40 Small Variety

Store None 72,800 0 ( 72,800) Unable to raise livestock

Respondent

Occupation Before and After Relocation Yearly Income Before and

After Relocation (P)

No. Age Before After Before After Change Remarks 31. 32. 33. 34. 27 Farming/Fishing None 59,280 0 ( 59,280) Directly affected, but can do other job 35. 64 Farming None — — — Directly affected, blurred sight, knows carpentry 36. 59 Fishing Fishing 62,400 31,200 ( 31,200) Not directly affected 37. 90 Farming/Fishing None — — — Directly affected, old age, supported by child 38. 59 Fishing None — — — Supported by child 39. 59 Fishing None — — — Supported by child 40. 54 Farming/Fishing None 46,800 0 ( 46,800) Directly affected but can still go fishing 41. 66 Farming/Fishing None 36,000 0 ( 36,000) Directly affected and supported by son 42. 73 Fishing None 33,800 0 ( 33,800) Had large compensation managed by son 43. 51 Farming Farming 49,992 9,000 ( 40,992) Directly affected but engaged in carpentry 44. 59 Farming None 36,000 12,000 ( 24,000) Directly affected, wife and son help the family 45. 36 Livestock/Vending Fish Vending 60,000 12,000 ( 48,000) Directly affected but assisted by husband 46. 52 Farming Small Variety Store 26,250 — — Directly affected, son still engaged in fishing 47. 49 Employee Employee — — — Two children also employed 48. 44 Buy and Sell Driving 240,000 48,000 ( 192,000) Decreased income not affected by relocation 49. 63 Fishing Fishing — — — Disabled but son is supporting 50. 43 Farming/Fishing With Using Multiskills 62,400 15,600 ( 46,800) Directly affected but using multiskills 51. 45 Mechanic Mechanic — — — Not affected by relocation 52. 55 Fishing Small Variety Store 26,000 26,000 0 Engaged also in backyard livestock raising 53. 32 Fishing Utility Aid — — — Not affected by relocation; employed in the National

Power Corporation 54. 33 Small Variety

Store Small Variety Store — — — Not affected by relocation

55. 76 Fishing None — — — Senior citizen but with children who work 56. 57. Average 134,372 75,150 ( 59,222) 58. Maximum 1,800,000 405,600 (1,394,400) 59. Minimum 26,000 12,000 ( 14,000)

— = no response. Source: Operations Evaluation Mission Survey.

ENVIRONMENTAL MONITORING RESULTS

Table A8.1: Ambient Air Monitoring Results Date of Reading 7-Mar-01 8-May-01 8-Aug-01 14-Nov-01 Monitoring First Quarter 2001 Second Quarter 2001 Third Quarter 2001 Fourth Quarter 2001

Concentration (micro-g/Ncm) Concentration (micro-g/Ncm) Concentration (micro-g/Ncm) Concentration (micro-g/Ncm)Location SO2 NO2 Particulate SO2 NO2 Particulate SO2 NO2 Particulate SO2 NO2 Particulate Resettlement Site 1.11a 3.15a 124.40 No data reported 0.52 n.d. 8.53 0.53 0.65 8.28 1.83a 3.38a 44.15 No data reported 0.00 n.d. 8.53 1.08 0.64 20.14 Inhobol 2.60b 5.24b 158.90 No data reported 5.45 0.87 59.80 0.53 0.88 28.68 0.79b 3.62b 67.76 No data reported 4.90 0.64 109.63 1.08 0.88 40.58 Candelaria 5.27 5.63 0.84 11.56 4.05 62.02 0.52 1.58 5.63 2.78 0.89 44.78 3.95 5.22 0.67 11.11 4.05 17.37 1.08 0.65 8.45 0.53 0.65 6.40 Palauig 3.07 5.00 3.60 15.98 3.33 40.44 3.80 n.d. 25.81 4.43 1.12 47.94 2.20 4.38 0.80 11.67 3.54 111.81 4.91 n.d. 17.65 5.51 1.11 22.41 DENR Limit 340 260 300 340 260 300 340 260 300 340 260 300 DENR Limita 130 ppb 140 ppb micro-g/Ncm = microgram per normal cubic centimeter, SO2 = sulfur dioxide, NO2 = nitrogen dioxide, ppb = parts per billion, DENR = Department of Environment and Natural Resources, n.d.=not detectable. a Readings by continuous monitor in ppb. Twenty-four hour averages of 2 days. b Readings by continuous monitor in ppb. Hourly peak in 24 hours. Source: Masinloc Thermal Power Plant.

Table A8.2: Marine Water Monitoring (In Situ Analysis) Date of Reading 9-Mar-01 8-May-01 18-Aug-01 14-Nov-01 Monitoring First Quarter 2001 Second Quarter 2001 Third Quarter 2001 Fourth Quarter 2001

DO Temperature DO Temperature DO Temperature DO TemperatureLocation pH (ppm) (Degrees C) pH (ppm) (Degrees C) pH (ppm) (Degrees C) pH (ppm) (Degrees C) Outfall (Discharge) 7.94 6.65 30.50 8.29 5.80 31.50 8.09 12.8 31.0 8.33 10.80 30.20Bani Point 7.97 6.65 28.60 8.26 5.40 29.80 8.20 15.4 29.6 8.37 11.00 28.40Cooling Intake 7.93 6.73 29.10 8.25 5.30 31.00 8.18 12.7 29.8 8.23 10.80 28.70DENR Limit 6.0–8.5 5.0 (min) <3.0 Rise 6.0-8.5 5.0 (min) <3.0 Rise 6.0-8.5 5.0 (min) <3.0 Rise 6.0-8.5 5.0 (min) <3.0 Rise C = centigrade, DO = dissolved oxygen, pH = pH value, ppm = parts per million, DENR = Department of Environment and Natural Resources. Source: Masinloc Thermal Power Plant.

Table A8.3: Continuous (Stack) Emission Monitoring Data (CEMS) (Snapshots) Unit Generation (MW) SOx (ppm) NOx (ppm) Date Maximum Average Maximum Average Maximum Average 30-Apr-02 290.0 227.6 214.0 107.8 368.0 220.0 16-Apr-02 301.2 267.7 244.0 161.3 321.0 267.7 25-Jun-01 302.4 294.8 80.0 38.2 557.0 520.5 22-Mar-00 306.0 300.4 420.0 297.8 538.0 447.4 12-May-99 301.6 299.9 303.0 275.2 287.0 259.9 DENR Limits 573 797 DENR = Department of Environment and Natural Resources, MW = megawatt, NOx = nitrogen oxides, ppm = parts per million, SOx = sulfur oxides. Source: Masinloc Thermal Power Plant.

ORGANIZATION CHART: NATIONAL POWER CORPORATION Corplan/Marketing Treasury & Risk Management Litigation/Bid Secretariat HR Services Corporate Communications Controllership Legal Counseling Training and Development Information System/Technology Corporate Financial Planning Land and Land Rights Materials Management and Information Services Management Group Welfare Fund Privatization and Restructuring Security and General Services External Office ESCo = Engineering Services Company, GENCO = generation company, PMEMCO = Plant Management and Equipment Maintenance Company, SPUG = Small Power Utility Group, TRANSCo = transmission company.

Development and Design Group

National Power Board

Office of the Corporate Secretary Internal Audit

Corporate Services

EXECUTIVE VICE-PRESIDENT AND COO

Aviation

SPUG Senior Vice-President GENCOs

Technical and Maintenance Services

Utility Management

Power Transmission Northern Luzon, Southern Luzon,

Visayas, Mindanao

Systems Operations Luzon, Visayas, Mindanao

Watershed Management

GENCO 1

GENCO 2

GENCO 3

GENCO 4

GENCO 5

GENCO 6

Corporate Services Group

Technical Services Group

Construction/Proj. Mgmt. Group

ESCO

PMEMCO

Senior Vice-President TRANSCos

Finance General Counsel

Contracts Management and Services

PRESIDENT AND CEO

HR and Administration