Philippines - Leyte - Cebu Geothermal Project

Document of The World Bank FOR OFFICIAL USE ONLY Report No: 20243 IMPLEMENTATION COMPLETION REPORT (LOAN 37000; 3700A; 37020) ONA LOAN IN THE AMOUNT OF US$211 MILLION TO THE NATIONAL POWR CORPORATION AND THE PHILIPPINE NATIONAL OIL COMPANY FOR THE LEYTE-CEBU GEOTHERMAL PROJECT MARCH 31, 2000 Energy and Mining Development Sector Unit East Asia and Pacific Regional Office This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.  CURRENCY EQUIVALENTS (Exchange Rate Effective as of March 20, 2000) Currency Unit = Philippine Peso (P) P1.00 = US$ 0.024 US$ 1.00 = P40.95 Average Exchange Rates during Project Years 1993 US$1= P27.12 1994 US$1= P26.42 1995 US$1= P25.71 1996 US$1= P26.22 1997 US$1= P29.47 1998 US$1= P40.89 1999 US$1= P39.06 FISCAL YEAR January 1 to December 31 ABBREVIATIONS AND ACRONYMS ADB Asian Development Bank BOO Build-Own-Operate BOT Build-Operate-Transfer DENR Departrnent of Environment and Natural Resources EIA Environmental Impact Assessment EOIS Efficiency and Operational Improvement Study ERB Energy Regulatory Board ESP Energy Sector Plan IDC Interest During Construction lPP Independent Power Producer LLGP Leyte-Luzon Geothermal Project NPC National Power Corporation PDP Power Development Program PNOC Philippine National Oil Corporation PNOC-EDC PNOC Energy Development Corporation PPA Power Purchase Agreement PTRP Power Transmission and Rehabilitation Project ROW Right-of-Way TGRP Transimission Grid Reinforcement Project Vice President: Jemal Kassum Country Manager/Director: Vinay Bhargava Sector Manager/Director: Yoshihiko Sumi Task Team Leader/Task Manager: Selina Shum  FOR OFFICIAL USE ONLY Philippines Leyte-Cebu Geothermal Project Loans No. 3700; 3700A; 3702 CONTENTS Page No. 1. Project Data ........................................................1 2. Principal Performance Ratings .......................................................I1 3. Assessment of Development Objective and Design, and of Quality at Entry .......................I 4. Achievement of Objective and Outputs ................. .......................................3 5. Major Factors Affecting Implementation and Outcome ........................................................9 6. Sustainability ....................................................... 11 7. Bank and Borrower Performance .................................................. .... 13 8. Lessons Learned ....................................................... 14 9. Partner Comments ....................................................... 15 10. Additional Information ....................................................... 16 Annex 1: Key Performance Indicators/Log Frame Matrix .17 Annex 2: Project Costs and Financing .19 Annex 3: Economic Costs and Benefits .21 Annex 4: Bank Inputs .24 Annex 5: Ratings for Achievement of Objectives/Outputs of Components .25 Annex 6: Ratings of Bank and Borrower Performance .26 Annex 7: Key Performance Indicators: Energy Sector Plan .27 Annex 8: Key Performance Indicators for NPC .32 Annex 9: PNOC-EDC Financial Indicators .34 Annex 10: Economic Value of Installed IPP Capacities ........................................ 35 Annex 11: PNOC-EDC Financial Rate of Return on Project Components . .37 Annex 12: ICR Mission Aide Memoire ..39 Annex 13: Borrower's ICR: PNOC-EDC ..45 Annex 14: Borrower's ICR: NPC ..56 This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.   Project ID: P004584 Project Name: LEYTE CEBU GEOTHERMAL Team Leader: Selina Wai Sheung Shum TL Unit: EASEG ICR Type: Core ICR Report Date: March 31, 2000 1. Project Data Name: LEYTE CEBU GEOTHERMAL LIC Number: 37000; 3700A; 37020 Country/Department: PHILIPPINES Region: East Asia and Pacific Region Sector/subsector: PT - Thermal KEY DATES Original Revised/Actual PCD: 10/16/89 Effective: 11/12/96 07/18/94 Appraisal: 04/13/93 MTR: Approval: 02/03/94 Closing: 06/30/98 09/30/99 Borrower/lImplementing Agency: NPC AND PNOC / NPC AND PNOC-EDC Other Partners: BOT Private Power Generation Contractors; Nordic Investment Bank/Nordic Development Fund STAFF Current At Appraisal Vice President: Jemal Kassum Gautam S. Kaji Country Manager: Vinay K. Bhargava Callisto E. Madavo Sector Manager: Yoshihiko Sumi Vineet Nayyar Team Leader at ICR: Selina Wai Sheung Shum Claudio Fernandez ICR Primary A uthor: Selina Wai Sheung Shum; Mikio Matsumura 2. Principal Performance Ratings (HS=Highly Satisfactory, S=Satisfactory, U=Unsatisfactory, HL=Highly Likely, L=Likely, UN=Unlikely, HUN=Highly Unlikely, HU=Highly Unsatisfactory, H=High, SU=Substantial, M=Modest, N=Negligible) Outcome: U Sustainability: UN Institutional Development Impact: M Bank Performance: S Borrower Performance: S QAG (if available) ICR Quality at Entry: U Project at Risk at Any Time: Yes 3. Assessment of Development Objective and Design, and of Quality at Entry 3.1 Original Objective: The objectives of the Project are to, inter alia, (a) improve the efficiency and overall performance of the energy sector; (b) assist the Borrower in meeting the rapidly increasing demand for electricity power in Cebu province, by expanding the geothermal power generation capacity and reinforcing its related power  transmission system; (c) strengthen the Borrower's financial viability and institutional capabilities to enable it to undertake its long-term investment program; and (d) promote private sector participation in geothermal power generation projects in the Philippines. The project objectives were consistent with the countrys priorities and the Bank's Country Assistance Strategy (CAS) prevailing at the time of project preparation/loan approval (1989-94). Specifically, the CAS aimed at assisting the country to regain a sustainable high growth path led by the expansion of an internationally competitive private sector through such priority measures as improved policy and project implementation as well as provision of infrastructure. The project design is directly relevant towards achieving the above objectives. Overall Energy Sector Performance. In agreement with the Bank, an Energy Sector Plan (ESP) was developed by the government to lay out policies and define improvements in all areas of concern in the sector as well as their completion schedule. Implementation of the ESP was supported by a series of Bank operations in the sector, including this Project. Power Transmission and Promotion of Private Power Generation. In response to the power crisis and the consequent opportunity cost of economic losses in the early 1 990s, the project objectives relating to the physical components were directed at ensuring the successful implementation of the Government's "fast track" Build-Operate-Transfer (BOT) private power program. In particular, they were essential to achieve the interrelated project objective of promoting private sector participation in geothermal power generation projects by transmission of the power generated. Strengthening the Finances of NPC and PNOC-EDC. The ESP noted above included actions directed at strengthening the finances of sector institutions, including the National Power Corporation (NPC) and Philippine National Oil Corporation - Energy Development Corporation (PNOC-EDC). The planned measures included privatization of the two institutions as well as various other actions (e.g. tariff adjustment, equity infusion) to enable NPC to achieVe financial viability. The minimum financial performance targets agreed with NPC and PNOC-EDC were incorporated in the financial covenants. Strengthening the Institutional Capability. The Project included a component for technical assistance and training to strengthen project implementation, enhance operational efficiency and power sector investment planning/reform. 3.2 Revised Objective: 3.3 Original Components: I . PNOC-EDC's Components comprised the following: (i) development of a 185 MW Geothermal steam field, including steam collection and power interconnection system (PNOC-EDC); (ii) carrying out a BOT Contract between PNOC-EDC and private sector companies to construct and operate 185 MW geothermal power plants; and (iii) technical assistence for project implementation. 2. NPC's Components comprised the following: (i) construction of an overhead transmission line in Leyte (about 77 km at 230 kV) and another in Cebu (about 93 km at 230 KV, and about 27 km at 138 KV); (ii) installation of submarine cables (about 32 km at 230 kV) linking the Leyte and Cebu lines; (iii) upgrading of NPC's existing 138 kV and 69 kV power transmission facilities in Cebu; (iv) provision of goods under the Energy Sector Project (to cover the impact of the Yen revaluation under the Bank's - 2 -  special commitment for irrevocable letters of credit); and (v) technical assistance consultancies for the design and preparation of tender documents for two hydro projects (totalling about 400MW); institutional support consultancies to implement the Project, NPC's Power Development Program (PDP) and the recommendations of the Efficiency and Operational Improvement Study (EOIS). 3.4 Revised Components: 3.5 Quality at Entry: Overall, quality at entry is rated as marginally unsatisfactory, with the PNOC-EDC components rated as satisfactory and NPC components rated as unsatisfactory. In hindsight, the project implementation schedule in the SAR proves to be overly optimistic in its critical assumption that NPC could successfully address the long standing implementation problems of tardy procurement and the right-of-way (ROW) issues. * NPC's implementation delays. At the time of project appraisal, the risks of NPC's tardy procurement procedures were considered to have been mitigated by the reorganization of NPC and all the key bids were underway. Further, NPC and PNOC-EDC had appointed high-level project directors to coordinate all project activities. The satisfactory implementation performance of PNOC-EDC's components confirmed their readiness for project implementation. By contrast, the substantial implementation delays encountered by NPC reflected, in part, its inadequate readiness for project implementation at the time of loan approval, particularly in regard to the resettlement action plan. Indeed, the project appraisal failed to identify the substantial risks related to ROW issues which had contributed to delays in the implementation of NPC's projects. * Risk Assessment. In light of the substantial uncertainties of the operating environment, it is not clear if a sufficiently rigorous risk analysis had been performed to avoid overly optimistic expectations of the project outcome related to NPC's finances and its project components, paying particular attention to the following: (i) the risks related to fixed obligations under the "take-or-pay" provisions of the BOT contracts, taking into account potential implementation delays, market risks and mismatch in currencies between the revenues and liabilities of the project entities; (ii) the risks of delayed and lower power tariff adjustments; (iii) the impact of competition from new IPPs and self-generation by industrial users; and (iv) the impact of combination of adverse factors on the project economics and entities' finances. 4. Achievement of Objective and Outputs 4. 1 Outcome/achievement of objective: This Project is one in a series of recent operations through which the Bank supported the implementation of the aforementioned ESP and reduction of bottlenecks in power transmission to promote economic growth. In particular, the Bank loan for the Power Transmission and Rehabilitation Project (PTRP) was approved six months prior to this Project and the Implementation Completion Report for the PTRP (dated April 1998) set a precedent for evaluating the outcomes of this and other subsequent projects in the series. Despite the achievement of physical objective. the overall project outcome is rated as unsatisfactory mainly because (i) NPC has maintained its precarious financial situation and the objective of strengthening the financial viability of the project entities has not been achieved; and (ii) the high cost of - 3 -  meeting the Project's physical objective was a contributing factor to this situation, and consequently a negative net present value (NPV) is currently estimated for the economics of the Project. NPC's financial viability was seen as critical for the improved performance of the power sector, since the Corporation's financial problems and consequent under-investment were considered to have been one of the key contributing factors leading to the power crisis. Hence, ensuring the sustainability of the Project's physical objective to eliminate the power crisis was also dependent on achieving the longer term financial objective. Sectoral Improvement Objective. Although many of the actions in the ESP have been implemented (Annex 7), a major issue of concern is the protracted delays by Congress in the passage of (i) a power sector restructuring bill; and (ii) a geothermal bill to increase financial incentives for investment in geothermal development. The current fiscal regime for geothermal development does not allow for a level playing field with competing imported fossil fuels (which are taxed at a much lower rate) and hinders private sector investment in the sector. Financial Objective. The legal agreements under this Project included the following financial performance covenants: (a) for NPC, a minimum of 8% rate of return (ROR) on revalued net fixed assets and a minimum debt service coverage ratio of 1.3 times; and (b) for PNOC-EDC, a maximum debt/equity ratio of 70/30, a current ratio of not less than 1 time and a minimum debt service coverage ratio of 1.25 time. BOT Obligations and Financial Ratios. At the time of project appraisal, BOT obligations were considered operating costs in the financial forecasts of both NPC and PNOC-EDC. On the other hand, the legal agreements did not make explicit reference to the treatment of BOT obligations in the definition of financial ratios, while the term " debt" was defined as "any indebtedness" of the Borrower maturing by its terms more than one year. Subsequently, the Commission on Audit (COA, state auditor in the Philippines) issued accounting guidelines on the BOT schemes which are considered capitalized lease and part of the liabilities of the project entities. In the case of a subsequent Bank-financed project for NPC, the Loan Agreement was amended to define "debt service" to include, inter alia, the BOT lease obligations, which was consistent with the approach of the co-financier, Asian Development Bank (ADB). However, in the case of PNOC-EDC, no such action was taken. Thus, notwithstanding the "take-or-pay" provisions in the BOT contracts and the above accounting treatment stipulated by COA, PNOC-EDC's calculation of the debt service coverage ratio has not taken into account the cash payment for BOT obligations, based on its interpretation that "the BOT arrangement is a mere provision of services whereby payment is contingent to the delivery of services". As such, this is a substantial deviation from the SAR approach (with internal cash generation net of BOT obligations) and that of the NPC (with debt service including BOT obligations). Similarly, the PNOC-EDC calculation of debt/equity ratio has excluded the liabilities for fixed BOT obligations. Consequently, the ICR mission initiated discussions with PNOC-EDC regarding the above issues; these will be followed up by the supervision mission of the Leyte Luzon Geothermal project. In hindsight, given the significant impact of the BOT obligations on the finances of the project entities, the legal agreements should have made explicit reference to the treatment of such obligations. (a) NPC. Despite the valiant efforts made by the NPC, the Corporation had not complied fully with the financial covenants for some years even prior to the Asian financial crisis (Annex 8). The precarious finances of NPC are largely due to factors beyond its control, including its under-capitalization and inadequate tariff adjustments. To meet its liquidity needs, NPC has incurred huge liabilities which, in turn, expose the Corporation to expensive debt service and "take-or-pay" obligations under IPP contracts. Its financial difficulties have been exacerbated by the recent regional financial crisis, particularly the impact of local currency devaluation (54% by end- 1997), lower energy demand and over-capacity in power generation. -4 -  Power sector restructuring, recapitalization and privatization of the NPC lie at the heart of the Corporation's recovery program. In particular, passage of the Electricity Industry Reform Bill would enable various measures to put NPC on the path to financial sustainability, including (i) the government to convert a substantial portion of its debt to equity; (ii) privatization of the NPC; and (iii) recovery of a portion of the stranded costs of NPC (including IPP obligations) through a universal levy on all electricity consumers. However, there are considerable uncertainties related to the timing of the passage of the Bill. In the absence of adequate remedial measures, NPC's finances will deteriorate further. In the interest of partnership, the ADB is taking the lead in power sector restructuring and privatization. It is understood that ADB has indicated to the government the need for a task force comprising the government, ADB and NPC officials to agree on an acceptable financial recovery action plan; the Bank will continue to coordinate closely with the ADB on this matter. (b) PNOC-EDC. Until 1997, PNOC-EDC had consistently complied with all of the above financial performance covenants (Annex 9). However, in its ICR (Annex 13), PNOC-EDC noted that it is ironic that the BOT scheme which helped in financing the power plant has required PNOC-EDC to seek external financing in order to pay part of the BOT obligations, due to the mismatch between electricity revenues (25 years sales contract with NPC) and BOT payments (10 years contract) and operating expenditures as well as the negative effect of the currency crisis affecting the Asian region. Consequently, PNOC-EDC reported noncompliance with (a) the current ratio covenant in 1997 and 1998; and (b) the debt service coverage ratio in 1998. Based on PNOC-EDC's unaudited financial statements in 1999, prior to the inclusion of the BOT lease obligations, its debt service coverage ratio was 1.5 times, current ratio at 1.7 times and debt/equity ratio at 55/45. On the other hand, if these financial ratios were to include the BOT obligations (as in the case of NPC), its debt service coverage ratio would have been reduced to 0.7 times, current ratio at 0.6 times and debt/equity ratio at 78/22. Over the medium term, PNOC-EDC's latest financial forecast indicated its expectation of improvement in profitability. However, even before the inclusion of BOT obligations, its debt service coverage ratio is projected to fall below 1 time in 2001, mainly due to the bullet repayment. After the inclusion of BOT obligations, the financial ratios would be weakened considerably. Thus, the financial risk noted above would need to be closely monitored and managed by PNOC-EDC. Physical Objective and Project Economic Rate of Return. The Project substantially achieved the objective of meeting the increasing demand for power in Cebu using indigenous and environmentally superior geothermal energy resources. Compared to the early 1990s, when the country was suffering from power shortages, consumers are unequivocally better served. However, this achievement came at a high cost (in 1999, average production cost of NPC plants was P1.76/kWh, whereas the average cost for NPC's contracts with the IPPs was P 2.66/kWh, of which the geothermal plants cost P 2.8/kWh) and the current estimate of the NPV is negative for the economics of the Project. Promotion of Private Geothermal Power Generation Projects. This objective was substantially achieved by the Project, although the actual cost is substantially higher than the appraisal estimate. This Project is the first phase of the Leyte Geothermal Project; together with the second phase Bank-financed Leyte Luzon Geothermal Project, geothermal power accounted for about 80% of the total power generation in the Visayas system in 1999.  4.2 Outputs by components: Physical Components I. PNOC-EDC's components (a) Development of a 202 MW geothermal steam field (which is higher than the SAR estimate of 185 MW), comprising the drilling of 12 production and reinjection wells (which are significantly higher than the appraisal estimate of 8 development wells), the construction of the fluid collection and disposal system, and the construction of a 230 KV interconnection system and switching station. Overall, implementation was on schedule and within budget and the output is rated as highly satisfactory. (b) Carrying out two BOT contracts with private companies to construct and operate geothermal power plants (Upper Mahiao and Malitbog Unit 1, totaling 202 MW). Achievement of the physical objective has come at an expectedly high cost (65% higher than appraisal estimate). Overall, output is rated as satisfactory. The PNOC-EDC components were completed on schedule, with the commissioning of the BOT plants in July 1996. These power plants are owned by a private company and will be transferred to PNOC-EDC after ten years under the present BOT contract. II. NPC's components (a) NPC constructed 48.7 km 230 kV and 5.8 km 138 kV transmission lines in Leyte, and 90.8 km 230 kV and 16.7 km 138 kV transmission lines in Cebu. This component was energized in July 1997, which was 12 months behind the appraisal schedule. Overall, output is rated satisfactory. (b) NPC installed 4 X 32 km of 230 kV submarine cables (cross sectional area is 630 square mm each) between Tabango (Leyte) and Talisay (Cebu). This component was completed in November 1997, representing a 17 months delay from the effective date (July 1996) for its power purchase agreement (PPA) with PNOC-EDC. This was mainly attributable to delays in procurement activities and accidental damage of the submarine cable when fiber optics cables were laid for a telephone company. Overall, output is rated satisfactory. (c) Cebu Grid Reinforcement: This component included installation of 26.9 km 138 kV transmission lines, a 100 MVA 138/69 kV substations, and additional transformers in three existing substations in Cebu. Implementation of this component has been delayed significantly mainly due to difficulties in right-of-way (ROW) issues and consequent need for changes of project sites. Thus, despite extension of the original loan closing date by 15 months (to September 30, 1999), one section of the transmission lines (currently under expropriation procedures) and a substation subcomponent have not yet been completed. Completion of these two subcomponents are scheduled for the second quarter of 2000 and April 2002, respectively. The incompletion of this component and the related output is rated as unsatisfactory. Institutional Component I. PNOC-EDC's component Technical assistance for project implementation. During all phases of the project, PNOC-EDC - 6 -  was assisted by consultants with extensive experience in geothernal development. The output of this component is satisfactory. II. NPC's components Technical assistance and institutional support for NPC. Major output included the following: (i) TA for the hydro projects included completion of final configuration of the scheme, documents for tendering, environmental assessment, and financial & economic viability of the project; and (ii) NPC was assisted by consultants for project implementation, especially tower design and submarine cable installation. NPC acquired an Integrated Resource Planning (IRP) software package for NPC's power development program and the supplier provided a training course on the software. NPC's system planners were able to enhance their capacity in conducting system analysis and planning. Various consultants assisted NPC to implement the EOIS recommendations including training for project management. The overall output of this component is satisfactory. Environmental/Resettlement Component I. PNOC-EDC's component is rated as highly satisfactory. PNOC-EDC prepared a detailed Environmental Impact Assessment (EIA) for the geothermal development. The Department of Environment and Natural Resources (DENR), based on its own evaluation, issued an Environmental Compliance Certificate approving the project implementation subject to protective measures during construction and operation. PNOC-EDC implemented the protective measures properly. A multi-sectoral task force composed of the DENR, NGOs, Local Government Units and PNOC regularly monitors compliance with relevant standards. PNOC-EDC has so far had no violations pertaining to air and water quality. Overall, the environmental/resettlement component of the PNOC-EDC's component is rated as highly satisfactory. The Corporation designed and implemented a resettlement program for families affected by the geothermal development. The program included (a) protection of residents from potential health hazards; (b) relocation of the residents from the project area; (c) assistance for the relocated community in regaining their standard of living prior to relocation; and (d) facilitating the formation of community institution and self reliance. The total number of households affected by the Leyte Geothermal Project was 106 and the resettlement program was successfully implemented, with about half of the affected households transferred to the newly constructed relocation site. II. NPC's resettlement component is rated as highly unsatisfactorZ. There have been significant delays in compensation payments by NPC, particularly for land acquisition, which are partly beyond the control of NPC in such cases as missing or incomplete documentation of some landowners. As of December 31, 1999, compensation payments remained only at 77%. Under the Resettlement Recovery Action Plan agreed in October 1999, NPC is committed to the completion of all the compensation payments by June 2000, except for cases where NPC has no control and cannot expedite payment due to incomplete documentation by affected landowners. Meanwhile, under the agreed action plan, NPC has established an escrow account for all the outstanding compensations, except for cases under expropriation (for which NPC has already provided provisional deposits). Further, the preparation of deeds of sales for land acquisition increased to 99% by February 2000. Implementation of the Resettlement Recovery Action Plan will continue to be monitored closely by the mission through NPC's monthly progress reports to the Bank. - 7 -  4.3 Net Present Value/Economic rate of return: During the power crisis in the country, the project was designed to meet the rapidly increasing demand for power in Cebu using indigenous and environmentally superior renewable energy resources. However, the current estimates of the economic benefits are sharply lower than the appraisal estimates (Annex 3). This is attributable to a combination of factors, including (a) significantly lower power sales in the initial years of operation (about 47% of full capacity production in 1998 and 1999) mainly due to lower than expected demand growth and delayed project completion; (b) significantly lower tariff levels than the appraisal estimates; and (c) total costs (including BOT lease obligations) were higher than the appraisal estimate. Least Cost Analysis. Based on the actual/latest cost data, and the assumptions of fuel oil and diesel prices (in constant 1993 price terms) at about $14/bbl and $19/bbl, respectively, the economic costs of the power investment program with the Leyte Cebu project were compared with those of the alternative program of isolated development for Visayas. The results indicated that at an NPV discount rate of less than 14% (as compared with the appraisal estimate of 29%). this Project is part of the least cost solution for the Visayas svstem. Based on a discount rate of 12%, the NPV of the savings associated with the program that includes this Project is currently estimated at $19 million (in constant 1993 price terms), which is significantly lower than the appraisal estimate of $165 million. However, one of the critical factors affecting the least cost analysis is the movement of petroleum product prices which is historically volatile. The results of sensitivity analysis indicated that a 20 % increase of the prices of fuel oil and diesel prices from 2000 onwards would result in about 2% increase in the break-even NPV discount rate (to 16%) between this Project and the alternative program of isolated development. According to PNOC-EDC's estimate, the competitiveness of geothermal energy to oil would only be affected if crude oil price is reduced to an average of $16/barrel from the present levels. Economic Rate of Return (ERR). The appraisal estimates of the ERR and NPV (at 12% discount rate) were about 16% and $89 million, respectively. Given the substantial uncertainties in the operating environment, the expected ERR could vary significantly under a wide range of scenarios. Based on NPC's latest financial projection to increase the average revenues to P3.54 /kWh (or US 4 cents/kWh, in constant 1993 price terms ) by 2004, the results of sensitivity analysis indicated that the ERR would be increased to (i) about 3 % in the event NPC's average revenues were to remain at the 2004 level for the balance of the project life; and (ii) 8 % in the event NPC's average revenues were to be the same as the appraisal estimate of US 7.1 cents/kWh from 2005 onwards. The overall project ERR is estimated to be negative if NPC's future average revenues were to remain at its 1999 level of P 2.34/kWh or US 6 cents/kWh (in current price terms). In summary, the current estimates of the ERR under a range of scenarios are significantly lower than the appraisal estimate and the NPV is expected to be negative. On the other hand, as in the case of the appraisal estimates, the current estimates of ERR are conservative since the unit benefits assumption has not captured other benefits to the economy encompassed in the consumers' surplus and the positive environmental impacts associated with geothermal development. 4.4 Financial rate of return: The overall financial rate of return (FRR) for PNOC-EDC's components and the BOT power plants are currently estimated at 9.8% (in real terms), which is close to the appraisal estimate of 9.5%, despite the significant divergence between the latest estimates and appraisal assumptions for selected key factors (Annex 11). In particular, due to the non-passage of the long delayed Geothermal Bill, the financial incentives (including royalty/tax holiday) anticipated earlier for geothermal development did not materialize. Consequently, the actual/latest estimate of power rate is P1 .65/kWh (in constant 1993 price - 8-  terms), which is 18% higher than the appraisal assumption of P1.4/kWh. It should be noted that the base case FRR estimated in the SAR has included sunk costs incurred by PNOC-EDC; this is useful for assessing whether the original decision to proceed with the project was well founded. However, consistent with standard Bank practice for ERR/FRR calculations, for the purpose of deciding whether to proceed with the incremental investment at the time of project appraisal, the sunk costs should have been excluded from the calculation of the FRR, as in the case of the ERR estimate in the SAR. With the exclusion of sunk costs, the overall FRR is currently estimated at 16.8 % based on the current contracted power price to NPC (as compared with the imputed appraisal estimate of 16.3% had the sunk cost been excluded). However, it should be noted that NPC received long delayed approval (in December 1999) for less than full cost recovery (P 1 .45/kWh) on the basis of "avoided cost" documented by NPC. In response, NPC has planned a two pronged approach to (i) apply to the Electricity Regulatory Board for full cost recovery with the requisite documentation requested by ERB, including the higher than expected contract price due to the nonimplementation of tax/royalty holiday noted above; and (ii) renegotiate the contract with PNOC-EDC. The results of sensitivity analysis indicated that if the power price were to be reduced to P1.45/kWh (in constant 1993 price terms) from 2001 onwards, the FRR would be reduced to 14% without sunk costs, and 7.9% with sunk costs. 4.5 Institutional development impact: Overall, the institutional development impact is rated as moderate. Achievement of this objective has been partial in the case of NPC. Specifically, the technical assistance subcomponents for the design of two hydro projects was implemented satisfactorily. However, further improvement is still required with respect to project management, most notably in procurement and resettlement aspects, as well as the need for closer integration between financial and non-financial planning within NPC. In the case of PNOC-EDC, the objective of institutional development has been substantially achieved. With the assistance of consultants with extensive experience in geothermal development, the Company demonstrated its competence by the satisfactory completion of the project in a timely and cost-effective manner. 5. Major Factors Affecting Implementation and Outcome 5.1 Factors outside the control of government or implementing agency: 3 Asian financial crisis was a significant external factor beyond the control of the government and the implementing agencies. Consequent sharp devaluation of the peso and slowdown of power demand growth contributed to the unsatisfactory outcome of this Project, both in terms of project economics and the objective to ensure the financial viability of NPC and PNOC-EDC. * BOT Power Plant Costs: The bargaining power of the government/PNOC-EDC to secure the best contractual terms from private investors (in 1993) was severely limited where there were power shortages and the country was rated as "non-investment" grade. Consequently, the substantial cost overrun for the BOT plants is attributable, in part, to a high risk premium required by the investors. * The submarine cables were accidentally damaged when fiber optics cables were laid for a telephone company. This has, in turn, contributed to substantial project implementation delays, higher project cost and lower project economics. * There have been significant delays in compensation payments by NPC, particularly for land acquisition, which are partly beyond the control of NPC in such cases as missing or incomplete documentation of some landowners -9-  5.2 Factors generally subject to government control: Pace and scope of energy sector reform * In the wake of the power crisis, the Executive Order 215 in 1990 repealed the Marcos decree on NPC's monopoly on power generation and allowed for private sector development of power plants and infrastructure facilities. In addition, development and implementation of the Energy Sector Plan by the government also contributed positively to the realization of this Project. * Ironically, introduction of competition from new IPPs contributed to NPC's loss of market share and exacerbated its financial difficulties. * The protracted delays in the passage of the power sector restructuring bill have, in turn, hampered the implementation of financial recovery action plan by NPC. * The levels and timeliness of power tariff adjustments fell short of the appraisal expectation, thus contributing to the unsatisfactory outcome in terms of the finances of NPC, project economics and sustainability. * The delayed passage of the Geothermal Bill has, in turn, affected adversely the finances and sustainability of PNOC-EDC and their components under this Project. 5.3 Factors generally subject to implementing agency control: Project Management, including among others, coordination among the relevant departments, procurement procedures and resettlement policies, has a significant impact on the performance of project implementation. 5.4 Costs and financing: The total financing requirements (including interest during construction) amounted to $612.98 million, which were $154.08 million or 34% higher than the appraisal estimate of $458.9 million (Annex 2). The BOT power plants accounted for the lion share ($112.8 million or 73%) of the cost overrun, while the balance was attributable to NPC's cost overrun. On the other hand, the Bank loan, totaling $193.11 million, was 8% lower than the original loan amount, mainly due to (i) co-financing with the Nordic Investment Bank/Nordic Development Fund subsequent to Bank loan approval for NPC's components; and (ii) higher amount of financing by PNOC-EDC's own internal cash generaton for geothermal development. (a) PNOC-EDC's Components PNOC-EDC's total financing requirements, including interest during construction (IDC) of $4.03 million, amounted to $ 92.04 million, which is close to appraisal estimate of $91.3 million (including IDC of $7.5 million). This is mainly due to higher than expected engineering and administrative costs (including well drilling costs not accounted for in the SAR, well development, geoscientific investigation and reservoir engineering costs) which were largely offset by the cost savings in well drilling. Of the original Bank loan ($64 million) to PNOC, which in turn onlent the proceeds to its subsidiary, PNOC-EDC, $53.03 million were disbursed, and the undisbursed balance ($10.97 million) canceled. The loan was closed on schedule in June 30, 1998. Under-utilization of the Bank loan was mainly due to PNOC-EDC's use of in-house rigs for well drilling which were not eligible for reimbursement under the loan. - 1 0 -  (b) BOT Power Plants The total cost of the two contracts with private power producers amounted to $287.5 million, which was 65% higher than the appraisal estimate. (c) NPC's Components The total financing requirements of NPC's components amounted to $233.5 million (including IDC of$ 23.5 million), representing an 21% cost overrun against the appraisal estimate of $192.9 million (including IDC of $16.5 million). This is mainly due to (a) the submarine cable contract ($95 million) which was 39% higher than the appraisal estimate ($68.6 million); and (b) the aforementioned accidental damage of the submarine cables which resulted in an additional cost of $15.9 million for repair as well as an additional $5.6 million for embedment. Upon the bid opening of the submarine cables contract which was substantially higher priced than the appraisal estimate, NPC secured co-financing from the Nordic Investment Bank/Nordic Development fund of $15.0 million. When the submarine cables were damaged, NPC secured additional co-financing ($25 million) from the Nordic Investment Bank. Further, financing of the subcomponent for reinforcement of the 138/69 kV substations ($4.8 million) was transferred to the ongoing Transmission Grid Reinforcement Project. Of the total Bank loan of US$ 147 million, US$ 140.08 million were disbursed. The loan was closed on September 30, 1999 after a 15 month extension, and a grace period (up to February 10, 2000) was granted for loan disbursement against eligible expenditures incurred before the loan closing date. As of February 10, 2000, undisbursed balance of US$ 6.9 million were canceled. 6. Sustainability 6.1 Rationale for sustainability rating: Overall, the prospects for project sustainability are uncertain in light of the considerable uncertainties of the operating environment, including the protraced delays encountered in the passage of enabling legislation critical for the financial recovery of NPC. In terms of responding to the power crisis, the Project has contributed to making it unlikely that "tpower crisis" will happen again in the country in the foreseeable future. In fact, rather than suffering from undercapacity, NPC now experiences a high reserve margin. Moreover, subsequent projects, including Leyte Luzon Geothermal and Transmission Grid Reinforcement projects, continue to improve the robustness of NPC's transmission network. However, meeting the Project's physical objectives came at a high cost, and has contributed to the perpetuation of NPC's already poor financial position and significant weakening of PNOC-EDC's liquidity position until the expiry of the BOT power purchase agreement (in 2006). Thus, one of the project objectives to strengthen the financial viability of NPC and PNOC-EDC have not been achieved. Since the financial viability of NPC is critical to ensuring an effective and efficient power sector, this means that the Project's sustainability as a whole is uncertain, taking into account the following factors: (i) general sectoral uncertainty caused by the protracted delay in the passage of an enabling legislation for power sector restructuring and the Geothermal Bill which would reduce the high royalty imposed on the geothermal industry and level the playing field with nominally cheaper but more polluting - 11 -  fossil fuel; and (ii) the current overcapacity in power generation is expected to continue over the medium term, coupled with the fixed take-or-pay IPP obligations of NPC, has an adverse impact on the Corporation's finances. 6.2 Transition arrangement to regular operations: (a) Transition Arrangements for the project's future operation The steam supply system of PNOC-EDC as well as interconnection connecting the developed power plants to PNOC-EDC Central switching station are operated by PNOC-EDC Leyte Geothermal Production Field Office. The Field Office is in charge of operation and maintenance of PNOC-EDC facilities in Leyte geothermal area, including production plan and coordination with the BOT power plants. It includes adequate experts including geologists to operate the geothermal steam system. PNOC-EDC has formed a Power Department in the Field Office to monitor the maintenance and operation of these BOT plants and will institute training program for PNOC-EDC staff. The BOT plants will be transferred to PNOC-EDC in the year 2006 under the current contract. The BOT contracts further provide PNOC-EDC personnel with training one year prior to the formal turn-over of the plants. Upon commissioning of the Leyte-Cebu interconnection of NPC as well as other transmission systems installed under the Project, the operation of these systems was transferred from the NPC Cebu Engineering Project Office, which was in charge of the construction, to Visayas Regional Center of NPC. Adequate maintenance would be provided to the facilities based on NPC's guidelines for maintenance. Special tools, instruments and boats for patrol and maintenance of the submarine cables are equipped with in switching stations at the both end terminals of the cables. (b) Performance indicators The following indicators will be monitored annually through the existing data acquisition systems from the Leyte Geothermal Production Field Office of PNOC-EDC and the Visayas Regional Center of NPC: (i) actual available energy and sales transferred to NPC Leyte-Cebu system from geothermal plants in Leyte; (ii) percentage of geothermal energy among energy sources for power generation in Visayas system; (iii) energy transferred from Leyte to Cebu through Leyte-Cebu interconnection; (iv) system reliability of the Visayas system; (v) system losses in Visayas system; and (vi) frequency deviation in the Visayas system. (c) Follow-up by the Bank The Bank has helped finance the second phase of the Leyte geothermal development project under the Leyte-Luzon Geothermal Project (LLGP, Loan 3746/3747-PH). The NPC transmission network has also been developed and reinforced under the LLGP and Transmission Grid Reinforcement Project (TGRP, Loan 3996/3997-PH). NPC has installed HVDC interconnection between Luzon system and Visayas system under LLGP and Northwestern Luzon 500 kV transmission lines under TGRP. TGRP has also included the establishment of a National Load Dispatch Center, which will allow for the operation of the interconnected transmission systems (Luzon, Visayas and Mindanao) in the country, once the planned Leyte-Mindanao interconnection is installed in the future. Under the TGRP, it was agreed with NPC that the Bank would monitor similar system performance indicators mentioned above for the three transmission systems. - 12 -  7. Bank and Borrower Performance Bank 7.1 Lending: The overall Bank performance in project identification, preparation and appraisal is satisfactory, with substantial inputs having been provided by Bank staff on both the policy front and extensive project preparation. However, selected aspects of the Bank's assessment had limitations, including (i) NPC's resettlement policy and action plan and the risks of right-of-way issues; (ii) the interrelated aspects of project entities' finances, BOT contracts and risk analysis of the Project and entities; (iii) inconsistencies in selected assumptions for the calculation of ERR and FRR. Moreover, the monitoring and evaluation indicators were oriented toward project output rather than outcome. 7.2 Supervision: * The overall Bank performance in supervision of this complex project, with two implementation agencies, is rated satisfactory. 3 Supervision of the procurement activities was generally satisfactory. However, there were inadequate follow up actions with NPC on resettlement issues during most of the project implementation period. Nevertheless, after the substantial completion of NPC's physical components, supervision efforts intensified on both the project level and country portfolio management level. * Exceptionally frequent changes in task manager and team members hampered the continuity and effectiveness of the supervision efforts. 7.3 Overall Bank performance: On balance, overall Bank performance is rated satisfactory. The above assessment of Bank performance is consistent with the comments by NPC and PNOC-EDC in their ICR (Annexes 13 and 14). Borrower 7.4 Preparation: Overall, the performance of both NPOC-EDC and NPC during extensive preparation for this complex project was rated satisfactory. Both corporations were committed to the Project and undertook the necessary upfront actions to meet all the Bank's conditions of Board presentation (conclusion of BOT/BOO contracts) and disbursement (effectiveness of BOT contracts for PNOC-EDC loan and implementation of demand charges for NPC loan). However, as noted above, the protracted delays encountered by NPC in the implementation of the resettlement action plan reflected its inadequate preparation and is rated highly unsatisfactory for this component. 7.5 Government implementation performance: Many of the actions in the ESP have been implemented and substantial progress has been made in reforming the energy sector (most notably in the full deregulation of the downstream oil industry). However, protraced delays in the passage of power sector restructuring bill and geothermal bill, as well as the levels and pace of power tariff adjustments, have significant adverse impact on the finances of the implementation agencies, project economic viability and sustainability. Nevertheless, it should be noted - 13 -  that the executive and legislative branches of the Philippine Government are independent of each other. While the executive branch can make several commitments to the Bank regarding policy (such as certifying a proposed bill), the passage of legislation is not within its sole control. Overall, the performance of the government is rated satisfactory. 7.6 Implementing Agency: On balance, the overall performance of the implementation agencies was rated as satisfactory. Project implementation by both entities was marked by many contracts being completed satisfactorily and within budget for most of the components. PNOC-EDC is rated as highly satisfactory for implementing the project on schedule and largely within budget. On the other hand, as noted above, NPC's procurement activities were tardy and its delayed implementation of the resettlement action plan is rated unsatisfactory. NPC's performance was hampered, in part, by changes in management and staff working on the Project. Separately, the financial objective of the Project was not achieved. However, as noted above (Secticns 4 and 5), a number of the critical factors contributing to this result were outside the direct control of NPC and PNOC-EDC during the project implementation period. 7.7 Overall Borrower performance: On balance, overall Borrower performance is rated satisfactory. 8. Lessons Learned 9 While "fast-track" BOT projects have proved crucial in alleviating power shortages, the economic efficiency of individual private investments should be improved with due consideration for (a) a cohesive sectoral approach, with special attention to prudent investment planning and financial management as well as risk management; and (b) rationalization of prices and risk sharing arrangements within a competitive and transparent framework. v It may not be realistic to expect power projects developed with private funds under the "fast-tracked" Independent Power Producer (IPP) Program to be least cost in the "traditional"sense; the additional cost over the hypothetical "least-cost" alternative is the price to pay for mobilizing resources that would otherwise not be available to the sector/country. = The high cost of the IPP Program has been a contributing factor to the failure of the Project to meet its financial objective and has adversely affected the project economics. Such an outcome indicates the need for sufficient risk analysis/management in a highly uncertain operating environment, particularly in a sector undergoing major structural reform. * Conventional economic rate of return analysis is poorly suited to an environment where higher-cost, sub-optimal investments are required to eliminate power shortages. In the case of NPC, the transmission investments to bring power from higher-cost plants are likely to be underutilized now that the power crisis is over. The main economic benefits were reaped in the first few years when power was scarce and the value of avoiding outages was very high. The quantification of benefits and the estimation of the economic rate of return is therefore critically dependent on the estimated value of unserved energy. * The use of a "rate of return on assets" target for financial performance is inappropriate for a company/sector with a very large and lumpy investment program. * In cases where such obligations as BOT contracts have significant impact on the entities' finances, the legal agreements should made explicit reference to the treatment of such obligations in the definition of financial covenants. * Quality at entry is a critical success factor for project implementation. In particular, for the - 14 -  resettlement component, resolution of the right-of-way (ROW) issue and completion of compensation payment is one of the pre-conditions prior to project construction. Moreover, an adequate risk analysis is essential for realistic expectations of project outcome. * In its ICR, NPC noted that as in the case of previous transmission line projects of the Corporation, the perennial ROW problem should be given top priority in terms of adequate policies and guidelines acceptable to affected landowners; adequate and qualified personnel to handle negotiations and expropriation cases; secure full support of other government agencies involved in the processing of ROW documents including speedy court decisions. These actions are vital in solving ROW problems of similar projects in the future. * In its ICR, PNOC-EDC noted that although the BOT scheme ensured the availability of private capital, there is a need to plan for possible funding deficits resulting from imbalance between project revenues and project operating and financing costs. * The complications associated with two implementation agencies (in different subsectors) under one project should be taken into account in the design of future projects. Indeed, in light of the diverse performance of the two project entities, the rating of project performance and outcome could be different if there had been two separate projects. * There are no short cuts to a successful complex operation; above-average inputs of Bank resources and broad staff skill mix for project design, appraisal and supervision are required. * Frequent changes of task manager and team members are not conducive to efficiency and effectiveness of the Bank's inputs. On the other hand, synergies may be achieved by a series of Bank interventions with the same project team. 9. Partner Comments (a) Borrower/implementing agency: Both NPC and PNOC-EDC provided data and comments which have been largely incorporated in the ICR, except for selected comments by PNOC-EDC which are summarized below: * Revision of the rating for "quality at entry" from marginally unsatisfactory to satisfactory since the rating is based on hindsight observations which were unforeseeable at the time of appraisal. Given the relatively positive economic environment and optimistic projections at the time of appraisal, the decision of PNOC-EDC to proceed with the Project would have been made even if sensitivities had been run up to the extreme downside the Philippine economy has seen in the past 2 years, simply because these conditions, at the time of appraisal, were unlikely. * The BOT setup was recommended by the Bank as an integral component of the project. Contrary to the Bank and the Company's initial expectations, the BOT setup was not the optimum way by which the project could have been implemented since this resulted in the short term funding gap as well as substantial VAT outlays. * Revision of the rating for financial objective for PNOC- EDC from unsatisfactory to satisfactory, the financial gap that PNOC-EDC is subject to is only short-term (1997-2006). * The ICR calculations of the estimated ERR of the project are largely pessimistic; the ERR calculations should include the impact of benefits to the economy not considered or not present during the time of appraisal, such as (a) avoided fuel importation brought about by higher fuels prices; (b) positive environmental impacts associated with geothermal development; and (c) reduced dependence on expensive power purchased or generated by diesel and gas turbines. From a macro perspective, the value of approximately $4.8 billion of power plant investments has been more than offset by an accompanying increase in GDP growth of $8.44 billion (Annex 10). * Deletion of IRR without sunk costs as it is irrelevant since the FRR inclusive of sunk costs, at 9.8%, is - 15 -  already viable. Similarly, deletion of reference to price adjustment which would only result in exacerbating the liquidity squeeze currently experienced by PNOC-EDC. * The unsatisfactory project outcome is only temporary and if viewed in the long term, the projected outcome will still be satisfactory. (1) Cofinanciers: Draft ICR was provided to the Nordic Investment Bank and its comments incorporated in the final ICR. (c) Other partners (NGOs/private sector): 10. Additional Information - 16 -  Annex 1. Key Performance Indicators/Log Frame Matrix Outcome / Impact Indicators: I. Leyte-Cebu Project - Energy transferred to NPC Leyte-Cebu - 1,370 GWh per year (1997-98) based on - 660GWh per year (July 1997- June 1998) system from geothermal plants in Leyte PPA - NPC: Percentage of geothermal energy for - not available - 69.95% in 1998 (compared with 52.08% in power generation in Visayas system 1995) - NPC: Energy transferred from Leyte to - not available - 843 GWh in 1998 Cebu through the interconnection system - NPC: System reliablity in Visayas system - not available - 99.79% in 1999 (compared with 99.60% in 1995) II. Overall NPC Operation Total NPC Energy Sales (GWh) -35,730 GWh in 1997 - 36,442 GWh in 1997 and 37,321 GWh in 1998 Power Sold/Total Pop. (kWh/person) -- 504 kWh/person in 1998 -- 508 kWh/person in 1998 - Sales per Oper. Employees (MWh) -- 2,926 MWh in 1997 - 3,152 MWh in 1997 and 3,143 MWh in 1998 -- % Total Energy Losses & Plant Use -- 6.9% in 1997 -- 6.50% in 1998 Ill. Financial Ratios - NPC's rate of retum on revalued net fixed 8% in 1997 7.2% in 1997 and 3.20% in 1998 assets no less than 8% - NPC's debt service coverage no less than 1.3 times in 1997 0.96 time in 1997 and 1.18 times in 1998 1.3 times - PNOC-EDC's debt service coverage ratio 1.7 times in 1998 0.7 time in 1999 no less than 1.25 times - PNOC-EDC's debt/equity ratio no more 41/59 in 1998 78/22 in 1999 than 70/30 - PNOC-EDC's current ratio no less than 1 3.9 times in 1998 0.6 time in 1999 time I/ SAR did not identify monitoring indicators for the Leyte Cebu Project per se; appraisal estimates for specific indicators for overall NPC operation and financial ratios are shown under the last PSR column. Further details of appraisal vs. actual are shown under Annexes 9 & 10. - 17 -  Output Indicators: PNOC-EDC to develop 185MW steamfield 202MW steamfield developed 202MW steamfield developed - NPC to (i) construct 50km 230kV and 7km - 48.7km 230kV and 5.8km 138kV - 48.7km 230kV and 5.8km 138kV 138kV transmission lines in Leyte; transmission lines constructed in Leyte transmission lines constructed in Leyte - NPC to (ii) construct 93km 230kV and - 90.8km 230kV and 16.7km 138kV - 90.8km 230kV and 16.7km 138kV 27km 138kV transmission lines in Cebu; transmission lines constructed in Cebu transmission lines constructed in Cebu - NPC to (iii) construct 32km submarine - 4x32km 230kV submarine cable (cross - 4x32km of 230kV submarine cable (cross cable linking Leyte to Cebu; section: 630 square mm each) constructed section: 630 square mm each) constructed beteween Tabango (Leyte) and Talisay beteween Tabango (Leyte) and Talisay (Cebu) (Cebu) - NPC to (iv) reinforce/upgrade existing Cebu - 26.9km 138kV transmission lines to be - The transmission line will be completed in transmission system constructed, but one secton still not the second quarter of 2000. completed due to RoW problem. construction of a 100MVA 138kV substation - 100MVA substation site finalized. The and installation of three additional completion of the substations will be in April transformers in existing substations not yet 2002. commenced due to RoW problem for the 1 OOMVA substation. - PNOC-EDC to engage in TA consultancy - TA successfully implementsed - TA successfully implemented for project implementation - TA for project implementation and PDP sucessfully implemented. Recommendations of EOIS partially implemented. - NPC to: (i) engage in TA consultancy for - TA for project implementation and PDP - TA for project implementation and PDP implementation of project, PDP and sucessfully implemented. sucessfully implemented. recommendations of EOIS Recommendations of EOIS partially Recommendations of EOIS partially implemented. implemented. - NPC to: (ii) engage in TA consultancies for - TA successfully implemented, but Pulangi - TA successfully implemented, but Pulangi Agbulu and Pulangi V hydro projects V hydro project has been dropped out from V hydro project has been dropped out from system development plan. system development plan. - PNOC-EDC to enter into BOT contract for - BOT contracts were awardea in - BOT contracts were awarded in 185 MW power plant August/September 1993. The BOT plants August/September 1993. The BOT plants (Upper Mahiao and Malitbog #1) were (Upper Mahiao and Malitbog #1) were commissioned in July, 1996. commissioned in July, 1996. End of project - 18 -  Annex 2. Project Costs and Financing Project Cost by Component (in US$ million equivalent) A. PNOC Geothermal Development Goods and Equipment 33.30 39.95 120 Works 35.80 32.23 90 Technical Assistance & Others 5.70 15.82 278 B. BOT Power Plant 157.80 287.48 182 C. NPC Transmission System Overhead Trans. Lines and Substations 65.60 62.60 95 Submarine Cables 59.00 95.00 161 Submarine Cable Repairment and embedment 0.0 21.50 Cebu Grid Reinforcement 9.80 7.40 76 Contracts under Energy Sector Loan 4.90 4.30 88 Right-of-Way and Compensation 3.80 12.00 316 Institutional Development 12.30 7.20 59 Total Baseline Cost 388.00 585.48 151 Physical Contingencies 24.60 Price Contingencies 22.20 Total Project Costs 434.80 585.48 135 Interest during construction 24.10 27.50 114 Total Financing Required 458.90 612.98 134 * Submarine Cable Repairment and embedment costs were not foreseen at the time of project appraisal - 19 -  Project Costs by Procurement Arrangements (Appraisal Estimate) (US$ million equivalent) 1. Works 31.00 10.00 0.00 3.30 44.30 (24.80) (4.00) (0.00) (0.00) (28.80) 2. Goods 175.40 0.00 16.50 0.00 191.90 (150.20) (0.00) (15.00) (0.00) (165.20) 3. Services 0.00 0.00 18.40 0.00 18.40 (0.00) (0.00) (17.00) (0.00) (17.00) 4. Compensation & 0.00 0.00 0.00 5.60 5.60 Administration (0.00) (0.00) (0.00) (0.00) (0.00) 5. BOT Plant 0.00 0.00 0.00 174.70 174.70 (0.00) (0.00) (0.00) (0.00) (0.00) Total 206.40 10.00 34.90 183.60 434.90 (175.00) (4.00) (32.00) (0.00) (211.00) " Figures in parenthesis are the amounts to be financed by the Bank Loan. All costs include contingencies 2'Includes civil works and goods to be procured through national shopping, consulting services, services of contracted staff of the project management office, training, technical assistance services, and incremental operating costs related to (i) managing the project, and (ii) re-lending project funds to local government units. Project Financing by Component (in US$ million equivalent) I [ ~~~~~~~~~~~~~~~PCrCentage Of APPraiSal Component APPraisal Estimate [ Actual/Latest Estimate Bank PNOCINPC CoF. Bank PNOC/NPC CoF. Bank PNOC/NPC CoF. PNOC Geothermal DevI. 64.00 19.70 53.03 34.98 82.9 177.6 0.0 IDC (PNOC) 7.50 4.03 0.0 53.7 0.0 0.0 0.0 0.0 BOT Power Plant 174.70 287.48 0.0 0.0 164.6 0.0 0.0 0.0 NPC Transmission 147.00 29.50 140.08 24.32 40.00 95.3 0.82 0.0 IDC (NPC) 16.50 23.50 0.0 142.4 0.0 0.0 0.0 0.0 TOTAL 211.00 73.20 174.70 193.11 86.83 327.48 91.5 118.6 187.5 Note: Co-financiers included BOT power plant contractors, Nordic Investment Bank/Nordic Development Fund - 20 -  Annex 3: Economic Costs and Benefits Least-Cost Expansion with Leyte-Cebu and with the Second-best Solution (in Constant 1993 Prices) US $ Million LEYTE-CEBU LEAST-COST SOLUTION ISOLATED SYSTEMS - SECOND BEST Total Energy TOTAL Total O&M Energy TOTAL NET Year Investment Fuel Cost O&M Cost Not SYSTEM Investment Fuel Cost Not SYSTEM SAINGS Cost Served COST Cost Served COST 1993 59.48 22.86 24.52 0.00 106.86 38.10 22.86 24.52 0.00 85.48 -21.38 1994 22.95 23.46 23.88 0.00 70.29 14.88 23.46 23.88 0.00 62.22 -8.07 1995 58.35 31.05 25.80 0.00 115.20 69.21 31.05 25.80 0.00 126.06 10.86 1996 154.65 56.46 45.62 0.00 256.73 42.87 56.46 27.12 0.00 126.45 -130.28 1997 6.00 57.88 70.00 0.00 133.88 53.28 54.93 53.68 0.00 161.89 28.01 1998 55.27 36.22 76.60 0.00 168.09 83.22 44.34 48.74 0.00 176.30 8.21 1999 12.03 21.53 80.26 0.00 113.82 88.93 29.57 47.47 0.00 165.97 52.15 2000 55.39 8.91 87.16 0.00 151.46 48.96 31.59 44.39 0.00 124.94 -26.52 2001 80.74 14.70 84.65 0.00 180.09 63.07 36.50 46.79 0.00 146.36 -33.73 2002 132.81 26.26 84.65 0.00 243.72 88.91 49.53 51.32 0.00 189.76 -53.96 2003 126.16 35.42 86.94 0.00 248.52 163.34 60.44 55.40 0.00 279.18 30.66 2004 90.73 43.09 89.23 0.00 223.05 165.81 84.12 55.27 0.00 305.20 82.15 2005 191.39 59.09 97.72 0.00 348.20 247.90 100.27 58.95 0.00 407.12 58.92 2006 146.50 79.55 99.31 0.00 325.36 162.96 108.07 65.65 0.00 336.68 11.32 2007 230.95 103.00 57.00 0.00 390.95 307.29 118.60 75.40 0.00 501.29 110.34 2008 313.72 117.05 64.17 0.00 494.94 414.14 137.53 83.23 0.00 634.90 139.96 2009 374.28 132.50 71.08 0.00 577.86 489.96 161.16 94.95 0.00 746.07 168.21 2010 375.28 150.24 83.87 0.00 609.39 339.08 178.44 105.90 0.00 623.42 14.03 2011 353.64 169.94 93.92 0.00 617.50 298.66 176.25 118.89 0.00 593.80 -23.70 2012 360.51 177.09 99.40 0.00 637.00 270.41 196.94 129.16 0.00 596.51 -40.49 2013 280.44 191.09 112.23 0.00 583.76 345.91 222.62 144.11 0.00 712.64 128.88 2014 73.61 211.47 128.38 0.00 413.46 89.73 256.57 158.66 0.00 504.96 91.50 2015 0.00 237.86 145.69 0.00 383.55 0.00 288.22 177.36 0.00 465.58 82.03 2016 -2482.90 237.86 163.27 0.00 -2081.77 -2814.51 288.22 177.36 0.00 -2348.93 -267.16 Present Values 10% 713.41 514.21 593.68 0.00 1,821.29 745.24 634.62 486.28 0.00 1,866.14 44.84 12% 619.28 409.66 492.56 0.00 1,521.50 641.69 503.75 394.90 0.00 1,540.35 18.85 15% 502.48 303.11 382.64 0.00 1,188.23 512.29 369.55 299.14 0.00 1,180.99 (7.24) 18% 412.19 234.25 305.90 0.00 952.34 411.96 282.30 235.09 0.00 929.34 (23.00) IRR: 14.0% - 21 -  Internal Economic Rate of Return Year Cost Unit Generation 13 Benefit Net Benefit Investment O & M 11 Total Benefit /2 0t1993 prices) (US$million) (US$million) (US$million) (Usc/kWh) (GWh) (US$million) (US$million) 1993 21.38 21.38 -21.38 1994 8.07 8.07 -8.07 1995 34.77 34.77 -57.82 1996 21.00 20.06 41.06 -162.69 1997 2.99 47.87 50.86 -53.20 1998 3.06 49.86 52.92 4.05 588.79 23.86 -31.82 1999 49.86 49.86 4.15 588.79 24.45 -25.42 2000 49.86 49.86 4.74 1,008.80 47.79 -2.07 2001 49.86 49.86 4.48 1,098.04 49.22 -0.65 2002 49.86 49.86 4.40 1,261.00 55.51 5.64 2003 49.86 49.86 4.16 1,267.50 52.78 2.92 2004 49.86 49.86 4.01 1,267.50 50.78 0.92 2005 49.86 49.86 4.01 1,267.50 50.78 0.92 2006 49.86 49.86 4.01 1,267.50 50.78 0.92 2007 9.21 9.21 4.01 1,267.50 50.78 41.58 2008 9.21 9.21 4.01 1,267.50 50.78 41.58 2009 9.21 9.21 4.01 1,267.50 50.78 41.58 2010 9.21 9.21 4.01 1,267.50 50.78 41.58 2011 9.21 9.21 4.01 1,267.50 50.78 41.58 2012 9.21 9.21 4.01 1,267.50 50.78 41.58 2013 9.21 9.21 4.01 1,267.50 50.78 41.58 2014 9.21 9.21 4.01 1,267.50 50.78 41.58 2015 9.21 9.21 4.01 1,267.50 50.78 41.58 2016 9.21 9.21 4.01 1,267.50 50.78 41.58 2017 9.21 9.21 4.01 1,267.50 50.78 41.58 2018 9.21 9.21 4.01 1,267.50 50.78 41.58 2019 9.21 9.21 4.01 1,267.50 50.78 41.58 2020 9.21 9.21 4.01 1,267.50 50.78 41.58 2021 9.21 9.21 4.01 1,267.50 50.78 41.58 Internal Economic Rate of Return 3.3% NPV @ 12 % -168 Notes: /1 Estimates only (at 1.5% of the investment cost). /2 1998-2000 are actual tariffs (by NPC to customers) while 2001-2004 are projected by NPC. /3 Net of 2.5% transmission loss /4 Assumptions for (a) P/US$ exchange rate: 41 in 2000; 42 in 2001; 43.5 in 2002; 45 in 2003; 46.5 in 2004; (b) local inflation rates: 7% in 2000; 5.5 in 2001; 4.5 in 2002; 4.0 in 2003; 3.5 in 2004; and (c) foregn inflation rates: 2.4% in 2000-2004. -22 -  Year ~~Cost Unit Gnrto 3 Benefit Net Benefit Investment 0 & M 11 Total Benefit /2 (M1993 prices) (US$million) (US$million) (US$million) (Usc1kWh) (GWh) (US$million) (US$million) 1993 21.38 21.38 -21.38 1994 8.07 8.07 -8.07 1995 34.77 34.77 -57.82 1996 21.00 20.06 41.06 -162.69 1997 2.99 47.87 50.86 -53.20 1998 3.06 49.86 52.92 4.05 588.79 23.86 -31.82 1999 49.86 49.86 4.03 588.79 24.45 -25.42 2000 49.86 49.86 4.85 1,008.80 47.79 -2.07 2001 49.86 49.86 4.25 1,098.04 49.22 -0.65 2002 49.86 49.86 3.49 1,261.00 55.51 5.64 2003 49.86 49.86 5.16 1,267.50 52.78 2.92 2004 49.86 49.86 4.06 1,267.50 50.78 0.92 2005 49.86 49.86 7.10 1,267.50 89.95 40.09 2006 49.86 49.86 7.10 1,267.50 89.95 40.09 2007 9.21 9.21 7.10 1,267.50 89.95 80.75 2008 9.21 9.21 7.10 1,267.50 89.95 80.75 2009 9.21 9.21 7.10 1,267.50 89.95 80.75 2010 9.21 9.21 7.10 1,267.50 89.95 80.75 2011 9.21 9.21 7.10 1,267.50 89.95 80.75 2012 9.21 9.21 7.10 1,267.50 89.95 80.75 2013 9.21 9.21 7.10 1,267.50 89.95 80.75 2014 9.21 9.21 7.10 1,267.50 89.95 80.75 2015 9.21 9.21 7.10 1,267.50 89.95 80.75 2016 9.21 9.21 7.10 1,267.50 89.95 80.75 2017 9.21 9.21 7.10 1,267.50 89.95 80.75 2018 9.21 9.21 7.10 1,267.50 89.95 80.75 2019 9.21 9.21 7.10 1,267.50 89.95 80.75 2020 9.21 9.21 7.10 1,267.50 89.95 80.75 2021 9.21 9.21 7.10 1,267.50 89.95 80.75 Internal Economic Rate of Return 8.1% NPV@12% -96 -23 -  Annex 4. Bank Inputs (a) Missions: Stage of Project Cycle No.of PersonsadSpeciat Perforrmance Rating =(e.g. 2Economists, : fF, etc.) Implementaton Develment 00L t> Month/Yearf 0 Count Specialty P307 70020; 0^70i ft ;)rogress Obiactive Identification/Preparation 5 1 FA, 2 PE., I EA and I Ec.. March 1992 July 1992 4 1 FA, I EA., I PE. and 1 PA. December 1992 8 1 PE, I EA, I Eg., 2 FA, I EEc. and I Lw Appraisal/Negotiation April 1993 6 2 FA, I PE. and I RS, I Lw, I DO Supervision June 1994 4 I Ec., 1 PE, I RS and I FA S S September 1994 3 1 EA, I PE. and I RS S S February 1995 7 1 Pr., I Ev., 2 FA, I PE, I RS, I S S Cp December 1995 4 1 EE, 2 PE and I ES S S July 1996 2 I ES and I FA U S August 1997 3 2 ES and I PvA S S February 1998 4 2 ES., I FS and I Rt. S S December 1998 2 1 ES., 1 OP S S June 1999 1 1 ES U S ICR November 1999 4 1 FA, I PE, I SI Spec. and, U U I OP January 2000 3 1 FA, 1 PE and I OP U U NOTE: FA = Financial Analyst; PE = Power Engineer; EA = Energy Advisor; Ec.= Economist; PA = Procurement Advisor; EEc = Energy Economist; Eg. = Engineer; Lw = Lawyer; RS = Reservoir Specialist; DO = Disbursement Officer; OP = Operations Officer; SI = Social Impact Specialist; ES = Energy Specialist; Pr. = Procurement; Ev. = Environmentalist; Cp. = Compensation; EE = Environmental Engineer; PvA = Privatization Advisor; Rt = Resettlement; SI Spec. = Social Impact Specialist; Missions for this Project were combined with those of other projects (b) Staff Stage of Project Cycle ActaULatestEstimate Identification/Preparation 102.6 225.3 Appraisal/Negotiation 43.6 104.9 Supervision 80.9 210.6 ICR 15.1 50.2 Total 242.2 591.0 - 24 -  Annex 5. Ratings for Achievement of Objectives/Outputs of Components (H=High, SU=Substantial, M=Modest, N=Negligible, NA=Not Applicable) Rating Z Macro policies O H OSUOM O N * NA 3 Sector Policies O H *SUOM O N O NA Z Physical O H *SUOM O N O NA [3 Financial O H OSUOM * N O NA Z Institutional Development 0 H O SUO M 0 N 0 NA Z Environmental O H *SUOM O N O NA Social Z Poverty Reduction O H OSUOM O N * NA Z Gender O H OSUOM O N * NA M Other (Please specify) O H OSUOM ON O NA Resettlement 2 Private sector development 0 H O SU O M 0 N 0 NA Z Public sector management 0 H O SU O M * N 0 NA E Other (Please specify) - 25 -  Annex 6. Ratings of Bank and Borrower Performance (HS=Highly Satisfactory, S=Satisfactory, U=Unsatisfactory, HU=Highly Unsatisfactory) 6.1 Bank performance Rating El Lending OHS OS OU OHU al Supervision OHS OS OU OHU L Overall OHS *OS O U O HU 6.2 Borrowerperformance Rating E Preparation OHS OS OU O HU E Government implementation performance 0 HS O S 0 U 0 HU a Implementation agency performance 0 HS 0 S 0 U 0 HU E Overall OHS OS O U O HU - 26 -  Key Performance Indicators - Energy Sector Plan Implementation Status [ Issues/Areas of Action Required Action Implementing Agency/Schedule Status (by March 2000) A. GENERAL/INSTITUTIONAL I) Energy Sector Coordination Establish the Department of Energy (DOE) President/Congress, December 1992. Done. Formalize DOE organization. DOE Secretary, March 1993. Done. 2) Privatization Propose clear congressional policy statement ECC/President Done. on private sector involvement in energy projects. a) NPC/Power Sector Complete OEA-commissioned study of OEA-Price Waterhouse, November 1992. Done. privatization options Submission of privatization plan. DOE, NPC, September 1993. Done. Approval of privatization plan. Cabinet, March 1994. Continue BOT approach for new projects; NPC, June 1993. 1000 MW Sual Coal Fired Plant in Luzon - conduct bidding and come up with short list for Energy Conversion Contract Signed in 1994; the 900 MW and 200 MW BOT coal plants for plant commissioning in 1999 Luzon and Mindanao, respectively. 200 MW Mindanao Coal Fired Plant deferred-- commissioning in 2006 Complete evaluation of bids. October 1993. 10 contracts for 2300 MW already signed with the private sector. Other than the ABB BTO's Awarding of contracts. December 1993. (600 MW) all are BOT contracts. 3) Oil Industry Deregulation Congressional policy statement on oil industry President/Congress, December 9, 1992. Done (DOE Law). deregulation. Complete ERB Energy Pricing Study. ERB/IDP, June 1993. Final study issued in March 1993. Complete industry cost structure study. DOE/K&M, August 1993. Draft report submitted March 1993. Recommend presidential endorsement of bill DOE/ERB/OP, September 1993. Done. amending OPSF's law to effect automatic price adjustments.  Key Performance Indicators for Project Operation - Energy Sector Plan Implementation Status (continued) Issues/Areas of Action Required Action Implementing Agency/Schedule Status (by March 2000) j Set maximum oil industry rate of retum. ERB/Oil Companies, September Done. ERB set a 10.6% average ROR for Oil 1993. Companies (April 16, 1993) Submit program for oil decontrol and other DOE, 1996. Republic Act No. 8180, Oil Deregulation Law deregulation activities. approved on March 29, 1996, but the law was declared unconstitutional by the Supreme Court on November 5, 1997, and is therefore invalid. Congress approved a new and more competitive deregulation law in February 1998. Approval of deregulation program. Cabinet, 1996. - do - Recommend presidential endorsement of ERB ERB/OP, 1996. - do - charter to allow decontrol of oil prices. Deregulate dealership activities (deregulation DOE, 1996. - do - measures non-price related would be advanced whenever feasible). Remove inter-fuel price subsidies. DOE/ERB, 1996. - do - 0o Draft bill rationalizing the tariff tax component of DOE/ERB/OP, 1996. - do - petroleum product prices. Recommend presidential endorsement of draft bill. DOE/OP, 1996. - do - Submit petroleum import/export liberalization DOE/ERB, 1996. - do - schedule. 4) Single Price-Regulatory Body for Utilities Legislation placing NPC and REC's under ERB Congress/President. Done. DOE Law in operation. price regulation. 5) More Efficient Approval System for Energy Presidential directive to DAR, DA, NEDA, DENR, ECC, DAR, NEDA, DENR, Done. Projects November 1992. November 1992. Agreement between DENR and RDC regarding DENR/RDC, June 1993. Done. Latest guidelines for ECC processing issued in approval requirements and time limit for action. July 1994. Agree to approve power projects on a program NPC/NEDA, June 1993. Completed March 1993. basis instead per individual projects. NPC to develop standard BOT contracts for various NPC/NEDA, September 1993. Model contracts for coal, diesel and gas turbines power plant technologies. already developed. Approval of standard contracts. NEDA-ICC. One month after completion of contract by NPC.  Key Performance Indicators for Project Operation - Energy Sector Plan Implementation Status (continued) Issues/Areas of Action Required Action Implementing Agency/Schedule Status (March 2000) B. POWER SECTOR 1) Availability and Reliability of Supply Ensure completion of fast track projects. NPC/DOE, October 1993. 6 BOT contracts in operation. Ensure implementation of power development NPC/DOE, ongoing. PDP approved by ICC and presented to the Cabinet in program. May 1993. Submit plan to rehabilitate or retire/replace aging NPC, December 1993. Done. plants. Evaluate and approve NPC plan and allocate NEDA. January 1994. Done. OPSF and PAGCOR grants approved. funding for technical assistance. Adopt rehabilitation or retirement plan for old Rehabilitation of Sucat 2 & 3 completed. plants. 2) NPC's Financial Viability Conduct more effective public information prograrn NPC/Cabinet, Oct-Dec 1992. Effective public information on price increase in place. on the need for NPC rate increase. Decision on acceptable rate of return base ERB, September 1993. Done. February 1993. methodology. Motion for early resolution by the Supreme Court NPC, May 1993. Tax exemption cases of NPC were resolved by the of NPC fuel tax exemption cases. Supreme Court favorably for NPC in the case of Maceda vs. Macaraig (197 SCRA 771). Approve automatic foreign exchange adjustment NPC, May 1993. Formula applied once exchange rate exceeded formula. P28/dollar. Implement rate adjustment to meet loan covenants. NPC, December 1992. NPC implemented tariff increase of P0.18/kWh from Develop annual projection of rate increase or NPC, end of each year. March 26, 1993, and additional P0.03/kWh from July decrease investment and overall financial 1993. requirement. Propose to DBM the level of government equity NPC, March each year. Approved for 1993. infusion to NPC. Submission of proposal for DBM, June each year. P3 billion from OPSF in 1993 approved by RA 7639, annual equity infusion to NPC. in addition to the PI billion annually Executive support of bill proposing equity infusion DOE. Done. to NPC. Complete operational efficiency improvement NPC/World Bank, December 1993. First phase report completed in March 1993. Draft study. report for Second Phase completed end of June 1993.  Key Performance Indicators for Project Operation - Energy Sector Plan Implementation Status (continued) Issues/Areas of Action Required Action Implementing Agency/Schedule Status (March 2000) 3) Rate Restructuring (Demand charges and Complete nationwide consultation, especially in NPC, August 1993. Ongoing. direct connections) Bacolod, Cebu and Mindanao. Implement rate restructuring down to distribution NPC/Cabinet, NEA/RECs, Done. level. ERB/PUs, December 1993. 4) Bataan Nuclear Power Plant (BNPP) Complete negotiations with Westinghouse. NPC-BNPP, December 1992. Negotiations failed. Decision on BNPP operation. Cabinet, March 1993. Proposal for conversion of BNPP to 1500 MW gas fired plant (BOT) was approved but discontinued due to excess generation capacity 5) Improve Electricity Distribution Efficiency Set limit to distribution loss that can be recovered NEA/ERB/ECC, ongoing. ERB Resolution 91-22 has set to reduce losses through tariff permitted in tariffs from 14% to 10% in 5 years. Presidential endorsement of anti-pilferage bill. ECC/OP, March 1993. Done. (RA # 7832). 6) Energy Efficiency Standards Finalize standards for power intensive appliances. OEA/BPS-DTI, June 1994. Building efficiency guidelines published March 1993. C. DOWNSTREAM OPERATIONS 1) Refinery Expansion Decide price adjustment for non-crude increase ERB, May 1993. Done. Firm up PNOC expansion plans. PNOC/DOE, January 1994. Done. 2) Coal Import Liberalization Implement financial/technical support program for OEA, January 1994. Initial program formulated. local coal. Reduce volume and tariff restriction. DOE/ERB/NEDA, June 1994. All coals in temporary exclusion list until June 1996. Anthracite and lignite having a 0% tariff and bituminous 10% tariff to 1999 and 5% thereafter, 3) Institutionalize Energy Conservation Executive endorsement of DOE bill with provisions President. Done (DOE Law). for continuation of energy conservation program. D. UPSTREAM OPERATIONS 1) Geothermal Law to Encourage Private Recommend presidential endorsement of pending DOE/PNOC/OP, June 1993. Senate hearings on SB 423 and 366 in April 1993. Still Sector Participation legislation on geothermal royalties and pending. development. 2) Improved Incentives for Oil and Gas Recommend presidential endorsement of pending DOE/OP, June 1993. Exploration legislation on oil and gas development.  Key Performance Indicators for Project Operation - Energy Sector Plan Implementation Status (continued) Issues/Areas of Action Required Action Implementing Agency/Schedule Status (March 2000) 3) Continued Exploration Momentum Conduct aggressive campaign to attract more oil Done. Generated by Recent Oil Discoveries explorations. 4) Promote Development and Utilization of Intensify research and development of DOST-PCIERD/OEA/PNOC/ Ongoing. Renewable Energy Technologies altemative/renewable energy technologies. NEA. Ongoing. Promote utilization of cost-effective alternative OEA/NEA. Ongoing. Ongoing. energy systems. Energy Sector Plan - Proposed Legislation Issues/Areas of Action Required Action Implementing Status (March 2000) Agency/Schedule 1) Energy Sector Coordination Enact legislation creating the Department of President/Congress Done. RA #7638, An act creating the Department of Energy. Energy. (December 9, 1992) 2) Oil Industry Deregulation Enact legislation amending the OPSF Law. December 1993. RA #8180, Oil Industry Deregulation Act was passed in 1996, but subsequently declared unconstitutional by the Supreme Court. in November 1997. Congress approved a new and more competitive deregulation law in February 1998. 3) Single Price-Regulatory Body for Utilities Included in the DOE Law. December 1992. Done. Enact into law ERB charter amendment. June 1994. Done. RA #'s 7638, 8180, 7832 & 8184. 4) NPC Financial Viability Approve annual equity infusion to NPC. December each year. Done. RA #7639, an Act providing payment in part of OPSF Enactment of law authorizing OPSF equity infusion to NPC. to NPC. 5) Improve Electricity Distribution Effticiency Enact effective anti-power pilferage legislation. December 1993. Done. RA #7832, Anti-Pilferage of Electricity & Theft of Enact law authorizing increase in NEA March 1994. Electric T/L Materials. capitalization. 6) Rationalize Oil Prices Enact law rationalizing the tariff and tax component 1996. Done. RA #8184, an Act Restructuring Excise Tax on of petroleum products. Petroleum Products. 7) Energy Conservation Refile and enact law institutionalizing energy December 1993. Done. EO #123, Institutionalizing the Committee on Power conservation. Conservation and Demand Management 8) Geothermal Law Enact law to encourage private sector participation December 1993. Pending (SB #726 and SB #888). in geothermal development.  Annex 8 Key Monitoring Indicators: NPC Appraisal Financial Year Ending 31- Dec. 1992 1993 1994 1995 1996 1997 ACHIEVEMENT OF GOALS: Total NPC Energy Sales (GWh) 23,835 25,305 28,825 30,212 32,958 35,730 NetNPC sales (Excl. Test-Run)- GWh 23,476 25,045 28,155 29,752 32,224 34,796 Power Sold/Total Pop. (kWh/person) 371 386 431 443 474 504 MANAGEMENT/EFFICIENCY: # Days Accounts Receivable 39 38 38 38 38 38 %Receivables on Billing 10.8% 10.4% 10.4% 10.4% 10.4% 10.4% Total Number Employees 11,055 14,210 14,210 14,210 14,210 14,210 #of Operational Employees 9,372 11,891 11,891 11,891 11,891 11,891 Personnel Cost on Revenues 3.8% 4.0% 4.7% 4.6% 4.3% 3.9% Personnel Cost on Oper. Costs 4.7% 5.0% 5.9% 5.7% 5.2% 4.7% Sales per Oper. Employees (MWh) 2,505 2,106 2,368 2,502 2,710 2,926 % Total Energy Losses and Plant Use 6.8% 7.4% 7.1% 7.0% 6.9% 6.9% FINANCIAL RATIOS: AverageTariff-P/kWh 1.6 1.7 1.9 2.1 2.4 2.7 Average Tariff Increase Centavos/kWh 20 11 23 16 26 30 Average Tariff- USc/kWh 6.0 6.2 6.6 6.8 7.4 8.0 AverageExchangeRatePesos/US$ 26.7 27.5 29.6 30.8 32.1 33.4 Working Ratio (1) 62.0% 59.3% 60.2% 61.0% 64.5% 67.2% Operating Ratio (2) 81.0% 78.6% 79.7% 80.2% 82.6% 83.8% Rate of Retum-NPC's Charter (3) 7.0% 7.8% 7.7% 7.7% 7.6% 7.6% Rate of Retum on Revalued Assets (4) 7.2% 8.1% 8.0% 8.0% 8.0% 8.0% Rate on Capital Employed (5) 1.2% -2.2% -2.8% -0.9% 0.8% 1.9% NetProfit-MillionUS$ 184 160 177 182 208 228 Net Profiton Equity 7.4% 5.8% 6.0% 5.2% 5.0% 4.4% Self-Financing Ratio (3-years Avg.) (6) -15.0% 25.0% 14.0% 19.0% 25.0% 27.0% Debt Service Coverage (7) 0.8 1.51 1.23 1.29 1.37 1.32 Interest Coverage (8) 1 .41 1.45 1.39 1.31 1.33 1.39 Debt/Equity Ratio (9) 50.0% 54.8% 55.6% 52.5% 47.7% 41.9% IN CONSTANT 1993 PRICES: AverageTariff-P/kWh 1.72 1.71 1.81 1.84 1.93 2.03 Real Tariff Increase Centavos/kWh 9 -1 1 2 9 10 Real Tariff Increase (Decrease) 5.6% -0.8% 6.2% 1.2% 5.1% 5.3% Critical Financial Indicators Between 1993-1998 Indicator Min. Average Max. Indicator Min. Average Max. ash-Mi]lPesos 4,673 10,589 18,324 Debt Service Ratio 1.1 1.3 1.5 AverageTafiff- P/kWh 1.71 1.88 2.03 Days Accounts Receiv. 38 38 38 Working Ratio 59.3% 63.4% 68.0% Debt/Equity Ratio 37.4% 48.3% 55.60/c Rate of Retum (Revalued) 8.0% 8.0% 8.1% 1/ Operational expenses excluding depreciation / operational revenues 2/ Total operational expenses (including depreciation & prov. for d/a) divided by operational revenues 3/ Operating income on net average fixed assets plus one sixth of cash operating expenditures 4/ Operating income on net average revalued fixed assets in operation 5/ Profit before interest and taxes / total equity and reserves 6/ Cash available from operations / 3-year average capital expenditures 7/ Operating cash flow divided by debt service (principal plus operational interest) 8/ Profit before interest and taxes / total interest (operational and capitalized) 9/ Long-tern debt / (long-term debt plus total equity) - 32 -  Key Monitoring Indicators: NPC Actual Operational & Audited Financial Results Financial Year Ending 31- Dec. 1992 1993 1994 1995 1996 1997 1998 ACHIEVEMENT OF GOALS: Total NPC Energy Sales (GWh) 23,958 24,805 28,745 31,031 33,381 36,442 37,321 Net NPC sales (Exci. Magellan & Test-Run) 23,875 24,712 28,520 30,356 32,549 36,442 36,429 Power Sold/Total Pop. (kWh/person) 395 409 474 452 487 496 508 NAGEMENTEFFICIENCY: # Days Accounts Receivable 38 39 36 38 37 38 44 %Receivables on Billing 10.70% 11.91% 10.33% 11.13% 11.22% 11.75% 13.93% TotalNumberEmployees 14,208 14,560 15,794 14,742 13,119 13,512 14,719 # ofOperational Employees 11,185 13,142 12,448 12,164 11,024 11583 11875 Personnel Coston Revenues 3.76% 3.85% 4.97% 6.41% 6.39% 6.21% 5.23% Personnel Cost on Operational Costs Sales perOper. Employees (MWh) 2,142 1,887 2,309 2,651 3,028 3152 3143 %Total Energy Losses &PlantUse 6.80% 6.80% 6.10% 6.80% 6.30% 5.90% 6.50% FINANCIAL RATIOS: Average Tariff- P/kWh 1.58 1.64 1.77 1.73 1.96 2.12 2.38 Average Tariff Increase Centavos/kWh 18 6 13 -4 23 16 26 Average Tariff- USc/kWh 6.3 5.9 7.3 6.6 7.4 5.3 6.1 Average Exchange Rate Pesos/US$ 26.7 27.1 26.4 25.7 26.2 29.5 40.9 Working Ratio/l 62.4% 60.3% 61.1% 56.9% 59.5% 64.1% 69.1% Operating Ratio/2 81.2% 83.5% 76.1% 78.0% 79.1% 84.9% 92.0% RateofRetum-NPC'sCharter/3 6.8% 5.7% 8.0% 7.0% 7.9% 6.9% 3.10% Rate of Retum on Revalued Assets 4 7.1% 5.9% 8.3% 7.3% 8.2% 7.2% 3.20% Rate on Capital Employed 15 11.4% 20.0% 18.8% 20.0% 22.2% 13.1% 14% Net Profit - Million US$ 91 51 282 152 211 104 -88 NetProfitonEquity 6.10% 1.90% 7.20% 3.70% 5.60% 2.70% -2.80% Self-Financing Ratio (3-years Avg.)/6 7.2% -11.4% 17.4% -7.4% -25.2% -46.9% -41.7% DebtServiceCoverage/7 1.14 1.51 1.15 0.98 1.12 0.96 1.18 Interest Coverage/8 1.32 2.36 2.37 2.39 2.75 1.43 1.32 Debt/Equity Ratio/9 49.8% 57.1% 49.9% 59.0% 75.1% 79.7% 77.4% IN CONSTANT 1993 PRICES: Average Tariff- PkWh 1.72 1.64 1.66 1.53 1.60 1.62 1.70 Real Tarifflncrease Centavos/kWh 9 -8 2 -14 7 2 8 Real Tarifflncrease (Decrease) 5.6% -4.7% 1.3% -8.2% 4.7% 1.6% 4.9% Critical Financial Indicators Between 1993-1998 Indicator Min. Average Max. Indicator Min. Average Max. Cash-Mill.Pesos DebtServiceRatio 0.96 1.15 1.51 Average Tafiff- P/kWh 1.64 1.93 2.38 Days Accounts Receiv. 36 39 4 Working Ratio 59.5% 61.8% 69.1% Debt/Equity Ratio 49.9% 66.4% 79.7/ .Rate of Retum (Revalued) 3.2% 6.7% 8.3% 1/ Operational expenses excluding depreciation / operational revenues 2/ Total operational expenses (including depreciation & prov. for d/a) / operational revenues 3/ Operating income on net average fixed assets plus one sixth of cash operating expenditures 4/ Operating income on net average revalued fixed assets in operation 5/ Profit before interest and taxes / total equity and reserves 6/ Cash available from operations / 3-year average capital expenditures 7/ Operating cash flow divided by debt service (ptincipal plus operational interest) 8/ Profit before interest and taxes / total interest (operational and capitalized) 9/ Long-term debt / (long-tenr debt plus total equity); long term debt included BOT lease obligation - 33 -  Annex 9 PNOC Energy Development Corporation Financial Indicators Appraisal _ 1991 1992 1993 1994 1995 1996 1997 1998 Revenues (peso:million) 1,367 1,499 2,373 3,463 4,504 5,679 11,032 18,533 Net Earnings 395 421 1,031 1,770 1,837 2,170 3,209 3,700 Net Working Capital 434 -110 3,250 3,979 3,601 3,498 3,715 6,616 Capital Assets 11,484 13,238 16,145 20,071 25,622 30,918 32,791 32,643 Long-Term Debt (Foreign) 4,859 5,056 9,032 10,820 14,340 17,579 16,782 16,206 PNOC Advances 3,231 1,774 0 0 0 0 0 0 Stockholders' Equity 4,009 6,576 10,504 13,597 15,250 17,203 20,091 23,421 Total Assets 12,978 14,764 20,650 25,477 30,871 36,230 40,946 43,461 Current Ratio 1.6 0.9 6.3 6.4 5.3 4.7 4.5 3.9 %LTDebt/(Debt+Equity) 67.2 51.6 46.8 44.3 48.5 50.5 45.5 40.9 Debt Service Times 48.9 2.4 2.2 3.5 2.8 2.1 2.8 1.7 Capital Expenditure 1,408 2,196 2,301 4,138 5,415 4,705 1,513 714 PNOC Energy Development Corporation Financial Indicators Actual 1991 1992 1993 1994 1995 1996 1997 1998 1999 Revenues (peso:million) 1,367 1,499 1,970 2,285 2,286 2,920 3,958 12,014 15,594 Net Earnings 394 422 607 1,207 730 797 -140 535 615 Net Working Capital -207 474 -341 -743 -118 1,147 -1,290 4,749 Capital Assets 11,484 12,496 15,927 18,324 22,721 25,128 69,582 68,762 72,643 Long-Term Debt (Foreign) 4,S59 4,911 9,286 9,972 12,068 15,973 19,843 20,099 25,592 PNOC Advances 3,231 2,078 0 0 0 0 0 0 Stockholders' Equity 4,009 6,389 10,386 13,631 14,075 14,667 14,369 15,252 15,814 Total Assets 12,981 14,372 21,136 25,272 28,431 34,986 80,880 78,767 82,202 Current Ratio /I 1.6 1.0 2.9 4.2 1.8 2.2 0.9 0.7 1.7 Current Ratio /2 1.6 1.3 3.4 9.1 3.0 3.0 0.7 0.6 0.6 % LT Debt/(Debt+Equity) Jl 67 53 48 43 47 53 58 57 55 % LT Debt/(Debt+Equity) /2 67 53 48 45 48 55 79 77 78 DebtServiceTimes/l 2.8 2.7 2.5 3.7 1.3 1.8 2.1 1.0 1.5 Debt Service Times /2 8.3 3.7 2.2 4.4 3.2 3.6 0.3 0.9 0.7 Capital Expenditure 616 1,128 1,047 679 1,325 1,257 1,165 773 392 Notes: 1) excludes the BOT lease obligations 2) includes the BOT lease obligations 3) 1991-1998: audited; 1999: unaudited - 34 -  Annex 10 Economic Value of Installed IPP Capacities I. Background The decision of the Aquino administration to mothball the 620 MW Bataan Nuclear Power Plant in 1986 and the inability to install replacement capacities contributed to the power crisis which started to be felt in the early nineties and the consequent decline in the economic growth of the country. Data regarding GDP at 1985 prices, Electric Sales and IPP installed capacities from 1986 to 1997 are shown in Chart 1. II. Economic Values of Installed IPP 1. Impact of Electricity Supply on Economic Growth Prior to the power crisis, the country was experiencing an average GDP growth rate at constant 1985 prices of about 6.5% per annum and electricity demand growth rate of about 10%. In 1990, the GDP growth rate started to decline to 3% and went further down to negative 0.5% in 1991 and 0.3% in 1992. During this period, electricity consumption was almost flat due to the lack of power capacities. With the entry of power plant capacities by Independent Power Producers starting 1992, its impact on the country's economic growth rate started to be felt, with the GDP growing by 3.8% in 1993 to about 8.7% in 1997 before the impact of the Asian currency crisis was felt by the country. During this period a total of 4,652 MW power plant capacities were installed with electricity sales registering an average increase of about 11.5% per annum. In could be seen from this analysis the importance of electricity supply to economic growth. 2. Economic Value of Installed IPP Capacities Starting 1993, the economic growth experienced by the country can be mainly attributed to the availability of power supply. From 1993 to 1997, the total value of the incremental GDP growth was about P157 billion pesos or about $8.44 billion dollars. For the same period, the additional electricity supplied by IPPs was about 11,323 gigawatt hours. This translates to an economic value of P13.8/kwh or $0.745/kwh. In terms of investment, the estimated cost of about $4.8 billion for the power plan installed by the IPP has been more than compensated by the increased gross domestic product realized by the country. 'Source: PNOC-EDC - 35 -  Electricity Sales vs. GDP 40 950 C 20 750 c 10 - . - 650 m 00 0 U U = 550 . 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 Years -A- Electticity Sales, GWH -U- Cumulative Installed IPP, MW GDP 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 ElectricitySales,GWH 17.85 19.431 21.573 22.731 23.323 23.625 23.769 24.692 28.449 30.791 33.i12 36.015 Cumulative Installed IPP, MW 0 0 0 0 0 0 0.072 1.278 2.472 3.605 4.305 4.652 GDP 591.423 616.923 658.581 699.448 720.69 716.522 718.941 734.156 766.368 802.866 848.451 891.53 - 36 -  Annex 11 PNOC-EDC FINANCIAL RATE OF RETURN ON PROJECT COMPONENTS: STREAMFIELD OPERATIONS (In Million Pesos Constant 1993 Price Terms) Year GWh Revenues Investment 0 & M Depre- Cum. Reco Cost Net Govt PNOC EDC PNOC EDC Sales 0.33/kWh Cost Cost ciation Cost Recovery Proceeds Share Share Cashflow 1992 _ 1,935.88 99 =1,161.53 = -= -1,935.88 1993 618.00 1,532.33 -618.00 1994 227.21 1,668.65 . -227.21 1995 953.06 2,240.49 _ _ -953.06 1996 1,370 285.96 586.96 37.21 131.60 2,761.47 257.37 28.60 17.16 11.44 -318.16 1997 1,370 285.96 93.99 28.94 137.55 2,726.99 257.37 28.60 17.16 11.44 174.81 1998 1,370 285.96 133.21 171.15 145.97 2,866.67 257.37 28.60 17.16 11.44 135.60 1999 1,370 285.96 197.25 145.97 2,952.53 257.37 28.60 17.16 11.44 268.80 2000 1,370 285.96 197.25 145.97 3,038.40 257.37 28.60 17.16 11.44 268.80 2001 1,370 285.96 197.25 145.97 3,124.26 257.37 28.60 17.16 11.44 268.80 2002 1,370 285.96 197.25 145.97 3,210.12 257.37 28.60 17.16 11.44 268.80 2003 1,370 285.96 197.25 145.97 3,295.98 257.37 28.60 17.16 11.44 268.80 2004 1,370 285.96 197.25 145.97 3,381.84 257.37 28.60 17.16 11.44 268.80 2005 1,370 285.96 197.25 145.97 3,467.70 257.37 28.60 17.16 11.44 268.80 2006 1,370 285.96 197.25 14.37 3,421.96 257.37 28.60 17.16 11.44 268.80 2007 1,370 285.96 197.25 8.43 3,370.27 257.37 28.60 17.16 11.44 268.80 2008 1,370 285.96 197.25 3,310.16 257.37 28.60 17.16 11.44 268.80 2009 1,370 285.96 197.25 3,250.4 257.37 28.60 17.16 11.44 268.80 2010 1,370 285.96 197.25 3,189.93 257.37 28.60 17.16 11.44 268.80 2011 1,370 285.96 197.25 - 3,129.82 257.37 28.60 17.16 11.44 268.80 2012 1,370 285.96 197.25 3,069.70 257.37 28.60 17.16 11.44 268.80 2013 1,370 285.96 197.25 3,009.59 257.37 28.60 17.16 11.44 268.80 2014 1,370 285.96 197.25 2,949.49 257.37 28.60 17.16 11.44 268.80 2015 1,370 285.96 197.25 2,889.36 257.37 28.60 17.16 11.44 268.80 2016 1,370 285.96 197.25 2,829.25 257.37 28.60 17.16 11.44 268.80 FRR (with sunk cost) 1.8% FRR (without sunk cost) 8.2% - 37 -  PNOC-EDC FINANCIAL RATE OF RETURN FOR INTEGRATED COMPONENTS (In Million Pesos Constant 1993 Price Terms Year Power ECA / Steam Depre- Income Net Total Sales 0 & M Cost ciation Tax Cashflow Project (1.65 / kWh) Cashflow 1992 0.00 -1,935.88 1993 0.00 -618.00 1994