Document of The World Bank

FOR OFFICIAL USE ONLY

Report No: 32348-PH

PROJECT APPRAISAL DOCUMENT

ON THE PURCHASE OF EMISSION REDUCTIONS

PROPOSED BY THE NETHERLANDS CLEAN DEVELOPMENT FACILITY

IN THE AMOUNT OF USD 2.5 MILLION

TO THE

PHILIPPINE NATIONAL OIL CORPORATION – ENERGY DEVELOPMENT CORPORATION

FOR A

NASULO GEOTHERMAL POWER PROJECT

June 2, 2005

Energy and Mining Sector Unit East Asia and Pacific Region

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.

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CURRENCY EQUIVALENTS

(Exchange Rate Effective May 19, 2005)

Currency Unit = Philippine Peso (P) P1 = US$0.0183 US$1 = P54.635

FISCAL YEAR January 1 - December 31

ABBREVIATIONS AND ACRONYMS

CDM Clean Development Mechanism CERs Certified Emission Reductions DBP Development Bank of the Philippines DOE Department of Energy EPIRA Electric Power Industry Reform Act ERPA Emission Reductions Purchase Agreement GHG greenhouse gas GOP Government of the Philippines MP Monitoring Plan NCDMF Netherlands Clean Development Mechanism Facility NEA National Electrification Administration NPC National Power Corporation PNOC-EDC Philippine National Oil Corporation-Energy Development

Corporation tCO2e tons of carbon dioxide equivalent

UNFCCC UN Framework Convention on Climate Change

Vice President: Jemal-ud-din Kassum Country Director: Joachim von Amsberg

Sector Director: Christian Delvoie Sector Manager: Junhui Wu

Task Team Leader: Selina Shum

CONTENTS

Page No.

A. STRATEGIC CONTEXT AND RATIONALE........................................................................ 3

1. Country and sector issues ................................................................................................... 3 2. Rationale for Carbon Finance (CF) involvement................................................................ 4 3. Higher level objectives to which the project contributes.................................................... 4

B. PROJECT DESCRIPTION ....................................................................................................... 5 1. Instrument ........................................................................................................................... 5 2. Project development objective and key indicators.............................................................. 5 3. Project components............................................................................................................. 5 4. Lessons learned and reflected in the project design............................................................ 6 5. Alternatives considered and reasons for rejection .............................................................. 6

C. IMPLEMENTATION ............................................................................................................... 6 1. Institutional and implementation arrangements................................................................. 6 2. Monitoring and evaluation of outcomes/results.................................................................. 7 3. Sustainability ...................................................................................................................... 8 4. Critical risks and possible controversial aspects................................................................. 9 5. Loan/credit conditions and covenants............................................................................... 10

D. APPRAISAL SUMMARY...................................................................................................... 10

1. Economic and financial analyses...................................................................................... 10 2. Technical........................................................................................................................... 12 3. Social and Environment.................................................................................................... 13

Annex 1. Power Sector Background.......................................................................................... 15 Annex 2. Major Related Projects Financed By the Bank and/or Other Agencies ..................... 19 Annex 3. Results Framework and Monitoring........................................................................... 20 Annex 4. Detailed Project Description ...................................................................................... 21 Annex 5. Project Costs............................................................................................................... 25 Annex 6. Implementation Arrangements................................................................................... 26 Annex 7. Financial Management and Disbursement Arrangements.......................................... 27 Annex 8. Procurement .............................................................................................................. 28 Annex 9. Economic and Financial Analyses ............................................................................. 29 Annex 10. Environmental and Social Safeguard Policy Issues ................................................... 37 Annex 11. Project Processing ...................................................................................................... 45 Annex 12. Documents in the Project File .................................................................................... 46 Annex 13. Baseline and Additionality Analysis .......................................................................... 47 Annex 14. Statement of loans and credits.................................................................................... 50 Annex 15 Country at a glance..................................................................................................... 52 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.

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Philippines Nasulo Geothermal Power Project

PROJECT APPRAISAL DOCUMENT

East Asia and Pacific Region

Energy and Mining Sector Unit

Netherlands Clean Development Mechanism Facility (NCDMF)

Date: June 2, 2005 Country Director: Joachim von AmsbergSector Manager: Junhui Wu Project ID: P089576 Instrument: Emission Reductions Purchase

Team Leader: Selina Shum Sectors: Renewable energy Themes: Infrastructure services for private sector development, Rural services and infrastructure, environmental policies and institutions

Project Financing Data [ ] Loan [ ] Credit [ ] Grant [ ] Guarantee [x] Other: Carbon Finance For Loans/Credits/Others Total Project Cost (US$m.): 35.4 Cofinancing: 35.4 Total Bank Financing (US$m.): $0 Proposed terms: yearly payments until 2012

Financing Plan (US$m.) Source Local Foreign Total PNOC-EDC IBRD/IDA Others Development Bank of the Philippines (DBP)

10.7

24.8

10.7

24.8

Borrower: Not applicable Responsible Agency: Philippine National Oil Corporation – Energy Development Corporation (PNOC-EDC) Estimated disbursements (Bank FY/US$m): N/A FY Annual Cumulative Project implementation period: 2005-2012 Expected effectiveness date: October 2005 Expected closing date: December 2013 Does the project depart from the CAS in content or other significant respects? Ref. PAD A.3

Yes X No

Does the project require any exceptions from Bank policies? N/A Have these been approved by Bank management? N/A Is approval for any policy exception sought from the Board?

Yes : No Yes No Yes X No

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Does the project include any critical risks rated “substantial” or “high”? Ref. PAD C.5

X Yes No

Does the project meet the Regional criteria for readiness for implementation? N/A

Yes No

Project development objective Ref. PAD B.2. The overarching objective of the proposed Project is to help mitigate global climate change by facilitating the use of market-based mechanisms sanctioned under the Kyoto Protocol through support to clean energy projects in the Philippines. The Project will assist the Philippines in stimulating and accelerating the commercialization of renewable energy applications and markets at the grid-connected level in order to reduce greenhouse gas (GHG) and other emissions, while responding to increasing energy demand and the need for energy diversification. Specifically, the proposed Project will obviate the need for equivalent capacity of fossil fuel-based generation to meet the projected power shortfall in the Visayas region, thus mitigating greenhouse gas emissions.

Project description Ref. PAD B.3. The Project comprises: (1) development of a 20 MW geothermal field, including the drilling of one production well (already completed) and the construction of the corresponding fluid collection and re-injection system (FCRS); (2) the construction, installation and commissioning of a 20 MW geothermal power plant, with gas abatement facility; and (3) the construction of a switching station at Nasulo to interconnect with Transco’s 138 kV transmission lines. The NCDMF will purchase CERs, targeted annually at 88,000 tons of Carbon Dioxide equivalent(tCO2e), from project commissioning (scheduled for end-2007) to 2012, at a price of about US$5.6tCO2e, totalling approximately $2.5 million. Which safeguard policies are triggered, if any? Ref. PAD D.3, Technical Annex 10

O.P. 4.01 – Environmental Assessment Significant, non-standard conditions, if any, for:

Board presentation: Not applicable

Loan/credit effectiveness: Not applicable Covenants applicable to project implementation: Not applicable

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A. STRATEGIC CONTEXT AND RATIONALE 1. Country and sector issues Dependence on imported and polluting fossil fuels The primary energy mix of the Philippines is characterized by a heavy dependence on largely imported fossil fuels which accounted for some 52 percent of the total energy supply in 2002. According to the Philippine Energy Plan (2004-2013), the share of fossil fuels is expected to increase, accounting for about 62% of the total energy supply in 2013. As a corollary for projected economic growth, demand for electricity is expected to increase from 48,467 GWh in 2002 to 111,210 GWh in 2013. Energy consumption for power generation is projected to increase from about 58 million barrels of fuel oil equivalent (MMBFOE) in 2002 to 70 MMBFOE in 2013. Coal-fired plants remain the dominant type of power generation in the country, accounting for 27% of total power generation, while oil-based power generation accounted for some 14% of the total in 2003. Energy security and environmental concerns In the wake of recent global oil and coal price hikes, the country’s heavy dependence on imported oil and coal has become a top priority concern for the Government of the Philippines (GOP). Moreover, coal and oil-fired power plants are major sources of environmental concerns at both the local and global levels. Energy supply accounts for over 26% of the country’s total greenhouse gas (GHG) emissions. Due to the projected increase in electricity demand, GHG emissions from the power sector is expected to increase from 14 million tons of carbon dioxide equivalent (tCO2e) in

1996 to about 60 million tCO2e in 2010 and 133 million tCO2e in 2020 (under a business-as-usual

scenario). The rural power sector contributes a disproportionately large amount of these emissions. This could be attributed to a number of factors, including (a) inefficiencies of many electric cooperatives and their lack of creditworthiness to tap investment financing to reduce high system loss; and (b) Philippines is a large archipelago comprising some 7,000 islands and, in remote islands and off-grid areas, electrification is characterized by a high dependence on diesel or bunker fuel for power generation, resulting in a higher carbon intensity than the Philippine energy sector as a whole. Given the GOP’s current goal to increase barangay (village) electrification from the current level of about 90% to 100% by 2008, and the fact that all the unelectrified barangays are in rural areas, emissions of GHGs are likely to increase at a rapid pace under the status quo scenario. Government Policy Response

• The Clean Air Act of 1999 aims to provide a comprehensive air pollution control policy for the

country. The challenge, however, is in implementation. • GOP ratified the UN Framework Convention on Climate Change (UNFCCC) in August 1994,

and more recently, the Kyoto Protocol in October 2003. Its Climate Change Action Plan endorses a shift from the current fossil-dominated energy mix to one that involves greater use of renewable energy resources. The United Nations Development Programme/Asian Development Bank/Global Environment Facility (UNDP/ADB/GEF) Asia Least-Cost GHG Abatement

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Strategy (ALGAS) report highlighted the crucial role of the energy sector in reducing GHG emissions and have identified the promotion of renewable energy (RE) as a strategic priority.

• Electric Power Industry Reform Act (EPIRA) of 2001 cited the State policy to promote the utilization of indigenous and new and renewable energy resources in power generation in order to reduce dependence on imported energy.

• GOP’s commitment to policy and institutional reforms necessary to remove barriers for rural electrification and RE development has been articulated in its Letter of Sector Development Program (dated March 2003) under the Bank/GEF-financed Rural Power Project.

• In 2004 energy independence has been declared as one of the five major reform agenda of the President of the Philippines. Towards this end, the action plan of the Department of Energy (DOE) includes, among others, (a) diversification of the energy mix to increase the reliability and security of energy supply, notably through aggressive development of RE; and (b) promotion of energy conservation, including through the recent introduction of a time-of-use power tariff.

• The RE Policy Framework issued by DOE sets ambitious targets to double the current level of renewable-energy-based power generation capacity by 2013 and to become the number one wind energy producer in Southeast Asia. This high scenario is based on the following key assumptions: (a) enhancement of existing policies and programs to establish a market-driven RE industry that is conducive to private sector investment and participation and encourages technology transfer and research and development; and (b) availability of international financing schemes (e.g., Clean Development Mechanism or CDM).

2. Rationale for Carbon Finance (CF) involvement It is proposed that the Carbon Finance Business purchase partial or entire emission reduction (ER) assets to be created by the proposed Project based on the following considerations: (a) the least cost alternative would be a polluting coal-fired power plant rather than the proposed environmentally friendly geothermal power plant; (b) this is the first time that the project sponsor, the Philippines National Oil Corporation- Energy Development Corporation (PNOC-EDC), is going to own and operate both the steam production and a power plant, rather than limiting its activities to the former; and (c) the main creditor, Development Bank of the Philippines (DBP), has required PNOC-EDC to endeavor to secure carbon credits as part of the loan conditions, as carbon credits will enhance the project cash flows. Other barriers to investment have been identified such as lack of availability of concessional financing for this type of plants after privatization of the sector, negative impact of peso devaluation in existing financing and barriers to investment in the energy sector in the Visayas for the past years, among others. The Carbon Finance Business (ENVCF) has already signed a letter of interest to purchase the certified emission reductions (CERs) under the project. The exact amount of CERs eligible for purchase will be subject to a Baseline Study that has been commissioned by ENVCF and to independent verification of energy output each year after plant commissioning. The purchase amount and price will be defined in an Emission Reduction Purchase Agreement (ERPA) to be reached through negotiation between the Bank and PNOC-EDC. A summary of the baseline and additionality analysis is in Annex 13.

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3. Higher level objectives to which the project contributes The overarching objective of the proposed Project is to help mitigate global climate change by facilitating the use of market-based mechanisms sanctioned under the Kyoto Protocol through support to clean energy projects in the Philippines. The Project will assist the Philippines in stimulating and accelerating the commercialization of renewable energy applications and markets at the grid-connected level in order to reduce GHG and other emissions, while responding to increasing energy demand and the need for energy diversification. Specifically, the proposed Project will obviate the need for equivalent capacity of fossil fuel-based generation to meet the projected power shortfall in the Visayas region, thus mitigating greenhouse gas emissions. The power plant is scheduled to commence operation in late 2007. Upon its full-year commercial operation starting in 2008, the plant is expected to sell about 150 GWh of power and mitigate about 88,000 tons of CO2 annually. This private sector-sponsored project is fully consistent with the Country Assistance Strategy (CAS, dated April 19, 2005, document number: 32141-PH) that includes improving rural infrastructure services for economic growth, strengthening private sector participation in infrastructure and enhancing environmentally sustainable development. This Project has been endorsed by the government for carbon financing, as it will contribute to the energy sector’s goal of expanding the use of indigenous energy resources and reducing the country’s heavy reliance on imported fossil fuels. B. PROJECT DESCRIPTION 1. Instrument It is proposed that the Carbon Finance Business purchase partial or entire emission reduction (ER) assets to be created by the geothermal power project upon the operation of this Project starting from late 2007 until 2012. The Emission Reductions Purchase Agreement (ERPA) between PNOC-EDC and the Bank, acting as trustee for the Netherlands Clean Mechanism Development Facility (NCDMF), provides for a price of about $5.6 per tCO2e and target annual CER purchase of about 88,000 tCO2e. As noted above, the exact amount of CERs eligible for purchase is determined by a Baseline Study and by independent verification of actual energy output each year after plant commissioning. 2. Project development objective and key indicators The project development objective is to create and trade GHG emission reduction credits under the CDM through the avoidance of thermal power generation. The key Project performance indicators will include (a) the quantity and cost of electricity generation/sales; and (b) actual CERs. 3. Project components The Project is located in the Palinpinon-2 [correct name? if not, change throughout document] geothermal production fields in the Southern part of Negros Island, central Philippines. The Palinpinon-2 field already supports existing power plants (totaling 80 MW) owned and operated by the National Power Corporation (NPC). The Project will “optimize” reservoir utilization within

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Palinpinon-2 by tapping excess steam for additional power generation capacity amounting to 20 MW1. The new power plant, to be owned and operated by PNOC-EDC, would contribute to meeting the growth in energy demand in the Visayas Grid over the medium and longer term. The Project comprises: (1) development of a 20 MW geothermal field, including the drilling of 1 production well (already completed) and 2 re-injection wells, as well as the construction of the corresponding fluid collection and re-injection system (FCRS); (2) construction, installation and commissioning of a 1 x 20 Geothermal Power Plant with H2S gas abatement facility; and (3) construction of a switching station in Nasuji to connect to NPC’s 138 kV transmission line. Once the power plant is operational, power sales are estimated at about 150 GWh annually. 4. Lessons learned and reflected in the project design The project design reflects decades-long experience of PNOC-EDC in geothermal reservoir management that enables extraction of an additional 20 MW of power generation capacity from the almost fully utilized Palinpinon-2 steamfield, without risk of affecting the output of the adjacent Palinpinon-1 field. This is ensured by PNOC-EDC through its conducting a very thorough resource assessment study that made long-term measurements of reservoir pressure prior to designing the power plant. The project design also reflects a conscious strategy to significantly reduce capital and operating costs by locating the power plant adjacent to existing facilities. This strategy would lower the cost of piping, civil works and interconnection to the transmission lines of the National Transmission Corporation (Transco). Operating and maintenance cost would also be reduced, since the same manning complement that operates and maintains the existing facilities could also be made responsible for maintaining the facilities of the new plant. Lessons learned from earlier CF projects have been incorporated in the Bank’s due diligence work, as well, including: a) the need to pay special attention to the implications of overall power sector restructuring and renewable energy policy on the Project, and b) the need to carefully assess the market and price risks involved in the proposed plan to sell power from the merchant plant to the Wholesale Electricity Spot Market (WESM). 5. Alternatives considered and reasons for rejection The alternative to this Project is to maintain the status quo of power supply addition from fossil fueled generating systems (mainly diesel). This alternative has been rejected because the shift from fossil fueled power generation to renewable forms of energy is a key strategy of the GOP to increase energy security of the country while minimizing the environmental impact of power generation.

1 Although the steam field for the proposed plant is also in the Nasuji Sector, the new plant would be called “Nasulo geothermal power plant (GPP)” to avoid confusion with the existing 20 MW Nasuji GPP. Nasulo is the name of the nearby fault.

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C. IMPLEMENTATION 1. Institutional and Implementation arrangements The Project will be implemented in accordance with the ERPA to be concluded between PNOC-EDC and the Bank, as trustee of the NCDMF. A Monitoring Plan (MP) will be agreed between parties to the ERPA. The ERPA and MP will define the quantity, price and other delivery conditions for CERs to be purchased by NCDMF as well as monitoring and verification systems and methods. Eligibility of C?ERs for purchase by NCDMF will be verified by an independent third party. Verification and certification of CERs generated annually by the Project will be coordinated by the NCDMF which will ultimately purchase the CERs. As per the requirement of the Kyoto Protocol, GOP will operate a registry to manage the transfer of CERs generated by the Project.

PNOC-EDC, the Project sponsor, will be responsible for implementation of the Project, including the following provisions under the ERPA:

• Maintain and operate the Project in accordance with sound business practices, proper due

diligence and high efficiency; • Undertake all reasonable efforts, including project documentation, to ensure eligibility of ERs

under Art.12 of the Kyoto Protocol; • Undertake, satisfactory to the Bank, actions agreed in the Environmental Management Plan

(EMP) to comply with the Bank’s safeguard policies; and • Notify the Bank of anything that may have an impact on the project or its capacity to deliver

ERs, including delays, material adverse changes and force majeure.

Specifically, in relation to CERs, PNOC-EDC will: • Monitor the emissions and other relevant parameters; • Organize periodic auditing of the project and verification that emission reductions have been

achieved in compliance with relevant project criteria, including the preparation of required reports;

• Prepare a brief annual or biannual report that should include: information on overall project

performance; emission reductions generated, verified and compared with targets; observations regarding MP baseline scenario indicators; information on adjustment of key MP assumptions, and calculation methods and other amendments of the MP; and

• Ensure certification of verified emission reductions.

Payment and flow of funds. After the ERPA becomes effective, NCDMF will only disburse against delivery of CERs. The involvement of the NCDMF with the Project will expire once CERs up to the total contract amount, as well as any Option CERs over which the option is exercised,

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have been delivered. In the event that the project sponsor fails to deliver the quantity of CERs for any given calendar year as set forth in the ERPA, it will be required to make-up the shortfall over the course of the following calendar year or other period agreed upon [FYI - there are other remedies including termination, which you may not need to mention here, but I wanted to bring to your attention in case you would like for this statement to be made complete]. 2. Monitoring and evaluation of outcomes/results Carbon Finance projects are initially evaluated on the basis of an ex-ante analysis of the emissions baseline (conventional generation and emissions that would have occurred in the absence of the project) and determination of project additionality. Project performance - and payment for CERs –is then monitored in accordance with the requirements of the MP incorporated in the ERPA by inclusion as a schedule to the ERPA and evaluated on the basis of achieving the expected CERs. Monitoring and evaluation of CERs are implicit in the project as a function of electricity generation as it occurs, with payment based on Megawatt hours (MWh) of generation as invoiced to the customer purchasing the electricity. To increase the likelihood that CERs acquired under the ERPA will satisfy the requirements of the UNFCCC and the Kyoto Protocol, Carbon Finance Business will retain the services of internationally-recognized, fully independent third parties to: a) provide validation of the sector-wide Baseline; and b) provide validation of the project design, the project specific Baseline Study (test of additionality against the sector-wide baseline), and the MP. This independent third party will also undertake periodic verification and certification of the ERs generated by each project and issue a Verification and Certification Report that includes:

• A statement of the amount of verified CERs the projects have generated in the relevant period,

• Other matters as may be required by the UNFCCC or Kyoto Protocol, and • Verification of compliance with Bank Safeguard Policies.

The validator will present a PDD, along with a description of the methodology chosen to measure the CERs and to demonstrate additionality, to the Executive Board of CDM, for its approval and registry under international rules. This approach ensures the creation of an environmental commodity that is recognized under existing laws of the Philippines and conforms in due course to the relevant international agreements. It is understood that these international guidelines may change, according to decisions by the Conference of the Parties to the UNFCCC and Kyoto Protocol. The project will be reviewed by the Bank during the construction phase of the Project [the word project is sometimes capitalized and sometimes not; may want to make uniform] to address areas of implementation weaknesses, especially concerning the EMP, accommodate changes in priorities, and ensure compliance with relevant Bank policies and procedures.

3. Sustainability The project entity, PNOC-EDC, was established on March 5, 1976 and has since then achieved remarkable success in geothermal exploration and development. Due to its decades-long experience in this specialized field, it has a track record demonstrating its technical competence in

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implementation of the proposed project. Indeed, PNOC-EDC is the beneficiary of earlier Bank loans which are closed, and its performance was rated highly satisfactory in the Implementation Completion Report (ICR) for the last two Bank-financed geothermal projects. Although it is just beginning to be involved in the task of operating the power plants themselves, sustained operation of the power plant itself is not expected to be a problem, given the extensive training to be provided by the power plant contractors which shall build the plant on a turnkey basis.

The 20 MW Nasulo power plant will utilize excess steam from the Palinpinon-2 field (optimization). The adequacy of the excess resource to fuel the commercial operation of the proposed plant for 25 years is supported by a thorough resource assessment study conducted by PNOC-EDC experts in 2002, and revalidated in 2005. The most crucial indicator is the reservoir pressure trend that has been shown to have stabilized starting in 2002. Along with thermal studies, the results show that the field could support the additional fluid extraction needed for a power plant of up to 40 MW. A specially designed fluid collection and re-injection system, and the planned drilling of makeover production wells at 5 year intervals during plant operation, assure technical sustainability of the project for 25 years. These results were reviewed by an independent expert commissioned by the Bank and found fully satisfactory. The finances of both the project and the project entity are expected to be satisfactory, as elaborated in the financial analysis below, including the results of sensitivity analysis which indicated that there is a substantial margin to cover the downside risks.

4. Critical risks and possible controversial aspects There are no controversial aspects foreseen in the project. Critical risks are described below: Risks Risk Mitigation Measures Risk Rating

with Mitigation To project development objective

Baseline risk

Baseline and monitoring methodologies used in the current projects have been approved by the CDM Executive Board.

M

To component results

Technical risk

Geothermal resource risk

Geothermal field development and geothermal power generation are mature technologies on which there is considerable local experience.

PNOC-EDC conducted thorough resource assessment study prior to plant design. Reservoir pressure trend from 1990 to 2005 confirms that field can support additional fluid drawdown for plant of up to 40 MW. Makeover production wells will be drilled periodically during plant operation.

M

M

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Risks related to PNOC-EDC’s lack of experience in power plant operation

Risks of project financing gap

Commercial risks

Bids for power plant will be required to include comprehensive training of PNOC-EDC staff prior to and after plant commissioning. Key specialists, e.g. turbine/generator spcialist, will be hired to augment training during operation. Moreover, PNOC-EDC is expected to be partially privatized by end-2005 by selling 40% of its shares to a strategic investor which is expected to augment the company’s technical and operational expertise.

DBP already approved a loan of P1.4 billion (US$24.8 million, at assumed exchange rate of P56.5 to US$1) to PNOC-EDC, with the requirement that the Project sponsor will endeavor to secure carbon credits under this Project. No problem is expected for PNOC-EDC to finance the balance of the project costs, about US$10.7 million, from its internal cash generation (in addition to financing the sunk costs of about US$1.1 million for steamfield development). Nevertheless, PNOC-EDC’s ability to self-finance investments will be included in the Bank’s due diligence work in assessing its financial viability.

During project appraisal, special attention will be paid to the assessment of the market and price risks involved in the proposed strategy to sell power from the project to WESM. Based on NPC’s current power tariff, PNOC-EDC's preliminary estimate of the project financial rate of return (FRR) is about 13%, which is well above the Company’s weighted average cost of capital (WACC) of about 9.6%, thus allowing a significant margin to cover potential downside risks. The Project sponsor, PNOC-EDC, is expected to remain profitable and its finances are expected to improve with the planned 60% privatization of the Company.

S

M

M

Overall risk rating M

5. Loan/credit conditions and covenants Not applicable [may want page break here] D. APPRAISAL SUMMARY

1. Economic and financial analyses (see Annex 9)

a) Project Returns The key variables that significantly impact the project economics and finances include the following:

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• Power sales – assumed to be about 150 GWh annually. Although the Project will be a merchant plant prior to the conclusion of bilateral contracts for the power sales, the risk of substantially lower market share is low, in light of DOE’s projected power demand for the Visayas grid and the lower cost of geothermal power as compared with such alternatives as diesel-fuelled power at the margin.

• Power Price – based on NPC’s current power tariff for the Visayas grid at P3.2646/kWh. The results of sensitivity analysis indicated that the break-even tariff is about P2.4/kWh, thus allowing for a 26% margin to cover the downside risk of power price.

• Project cost – PNOC-EDC’s cost estimates were based on prices in contracts recently placed by the Company [inconsistent capitalization for the word company throughout document]for similar works and estimates by its feasibility study consultants. For prudence, the base case for project returns are based on cost estimates higher than those of PNOC-EDC, as recommended by the Bank’s independent consultant, including higher unit cost of well drilling ($1.5 million per well) and two new re-injection wells. Details of the project cost are in Annex 5.

• Operating and maintenance costs – Power plant O & M costs have been assumed to be $35/kW/yr in PNOC-EDC’s feasibility study, along with steam field maintenance costs budgeted at around $300,000 per year, and these estimates are considered by the Bank’s geothermal consultant to be appropriate. In addition, allowance has been made for the drilling of one new production well every ten years.

• Project financing – The Development Bank of the Philippines (DBP) already approved a 15-year loan of P1.4 billion (US$24.8 million, at assumed exchange rate of P56.5 to US$1) to PNOC-EDC, with the requirement that the Project sponsor will endeavor to secure carbon credits under this Project. No problem is expected for PNOC-EDC to finance the balance of the project costs, estimated at about US$10.7 million, from its internal cash generation (in addition to financing the sunk costs of about US$1.1 million for steamfield development).

The Project is expected to start operation in December 2007. The costs and benefits estimated for the calculation of both economic and financial rates of return are assumed to be the same, except for the exclusion of taxes in the case of the economic rate of return (ERR). The main project benefits will be derived from sales of power, while carbon credits will contribute to additional revenues at the margin. The value of power generated from the Project is approximated by the current NPC generation tariff for the Visayas grid. It is a conservative assumption to use the existing tariff as a proxy for the consumers’ willingness to pay, as this does not take into account any consumer surplus of additional power deliveries to the grid.

Both the economic rate of return (ERR) and financial rate of return (FRR) are satisfactory, estimated at about 15% and 13.1% (in real terms), respectively. The results of sensitivity analysis indicated that even under the scenario of 15% lower net operating cash flows (as a result of lower revenues and/or higher operating costs), the FRR of 10.2% remains slightly above the weighted cost of capital of the project entity, estimated at about 9.7% (with its debt financing cost of about 9.5% p.a. before tax; and cost of equity assumed to be 10%). The carbon credits, estimated at about $492,800 per year, totaling about $2.5 million during the 5-year period of 2008-2012, are not expected to have a significant impact on the project returns (improving the FRR by 0.5%), although they facilitate the project sponsor’s access to credit for this Project, as noted above.

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b) Project Entity Recent Finances. PNOC-EDC has remained consistently profitable. However, since 1997, PNOC-EDC has experienced a liquidity squeeze, mainly due to the substantial mismatch between the terms of its power purchase and sales agreements. Specifically, its power purchase agreements, under five build-operate-transfer (BOT) contracts with private independent power producers (IPPs), are only 10 years, while its sale of electricity to NPC is covered by a much longer term, 25-year power sales agreements. Consequently, PNOC-EDC has to seek external financing in order to pay part of the BOT obligations to the IPPs. In addition, in 2004, PNOC-EDC reported a negative net worth for the first time in the Company’s history due to changes in Philippine accounting standards for foreign currency transactions and immediate recognition (rather than deferral) of foreign exchange losses. As a result, in recent years, PNOC-EDC has not complied with the minimum financial performance covenants under earlier Bank-financed projects, summarized as follows:

Financial Covenants 2002 2003 2004Actual Actual Estimated

Current Ratio (1.0 minimum) 0.63 0.83 0.92

Debt Equity Ratio (70% maximum) 76% 75% 119%

Debt Service Ratio (1.25 minimum) 1.01 0.92 0.87

Future Finances. PNOC-EDC has planned to implement a number of measures to improve its future finances, including the following: (a) review its plans and programs for operating budget and capital expenditures to identify controllable expenses for possible deferral and reduction; (b) continues to undertake profitable projects to improve its cash flow position over the medium and longer term; and (c) revive its plan to privatize 60% of its shares, with 40% targeted for sales to strategic operators and 20% through IPO in the Philippine stock exchange. If successful, PNOC-EDC’s future finances are expected to improve considerably, as indicated in the projected financial ratios below. Detailed assumptions, along with its projected income statements, cash flows and balance sheets over period 2005-2009 are in Annex 9. However, the projected improvements would not be sufficient to allow the Company to comply with the existing financial covenants for debt/equity ratio and debt service coverage ratio. Accordingly, PNOC-EDC has planned to request the Bank to consider amendment of the above financial covenants, viz to waive the above two financial covenants for 2005 and 2006, and to reduce the minimum debt service coverage ratio to 1 time, starting from 2007. In light of PNOC-EDC’s action plan to strengthen its finances, which is satisfactory, the Bank is expected to respond positively to this request.

Projected Financial Ratios 2005 2006 2007 2008 2009

Current Ratio (1.0 minimum) 1.52 1.78 1.80 1.43 1.12

Debt Equity Ratio (70% maximum) 86% 76% 66% 55% 39%

Debt Service Ratio (1.25 minimum) 0.88 0.93 1.11 1.05 1.04

- 13 -

2. Technical The Philippines remains the world’s second largest user of geothermal energy for power generation with 1,931 megawatts (MW) of installed capacity. The total potential in the country is estimated to be4,790 MW, of which 2,047 are proven reserves. Development of this indigenous energy resource is a key part of the Government’s policy for security of fuel supply. The Philippine Energy Plan for 2003-2013 schedules 860 MW of indicative geothermal capacity addition within the ten-year planning period to address the forecast additional capacity requirement, largely in Luzon. PNOC-EDC is one of only two companies that have been developing geothermal fields in the Philippines from the inception of the geothermal energy program. Thus, it has acquired decades-long experience in steamfield development and “optimization” and is well positioned to develop and operate the proposed Project. Although it is just beginning to be involved in the task of operating the power plants themselves, this is not expected to be a problem, given the extensive training to be provided by the power plant contractors. More crucial in the case of this Project, which will utilize excess steam from an existing, almost fully-used field, is PNOC-EDCs expertise in technical assessment of the resource and in designing a strategy for its optimal use. It would be important to ensure that the proposed 20 MW Nasulo power plant could be supported for 25 years by the geothermal resources and that the operation of this Project will not adversely impact the operation of other power plants already operating in both Palinpinon-1 and Palinpinon-2 fields. For this purpose, PNOC-EDC conducted in 2002 a thorough resource assessment study that included estimation of volumetric stored heat to ensure adequate thermal capacity, decline curve analysis using lumped parameter modeling to assess pressure drawdown of the new plant, and reservoir pressure trend analysis for the Palinpinon-2 field. Periodic reservoir pressure measurements in several wells were in fact initiated in 1990, and continued well after the pressure had stabilized in 2002 and plans for the power plant had been drawn up. Measurements made in 2005 showed stable reservoir pressure and provided full confirmation that, with appropriate fluid re-injections, the field can support the additional fluid extraction needed for commercial operation for 25 years of a new geothermal power plant of even up to 40 MW. An independent review by a geothermal expert commissioned by the Bank concluded that the resource assessment study done by PNOC-EDC is fully satisfactory and that the design of the power plant and the fluid collection and re-injection system is consistent with international standards. 3. Social and Environmental (see Annex 10)

a) Environmental Category and Safeguard Policies Triggered The Project is assigned Environmental Category B based on the following considerations: (i) the Project is an add-on to existing operations; (ii) the design includes re-injection of spent geothermal fluid back to the geothermal reservoir which avoids discharge of brine into rivers and water channels while providing continuous recharge to the geothermal reservoir; and, (iii) the project proponent has a proven track record of good performance in environmental and social safeguards.

- 14 -

Applicable? Safeguard Policy If Applicable, How Might It Apply?

[x ] Environmental Assessment (OP/BP 4.01) [ ] Natural Habitats (OP/BP 4.04) [ ] Pest Management (OP 4.09)[ ] Involuntary Resettlement (OP/BP 4.12) [ ] Indigenous Peoples (OD 4.20)[ ] Forests (OP/BP 4.36) [ ] Safety of Dams (OP/BP 4.37) [ ] Cultural Property (draft OP 4.11 - OPN 11.03)[ ] Projects in Disputed Areas (OP/BP/GP 7.60)*

[ ] Projects on International Waterways (OP/BP/GP 7.50)

The Environmental Assessment (EA) Policy is triggered due to project activities that may have environmental impacts, such as: land clearing and civil works associated with the preparation of the 1-ha power plant site, the 0.5-km access road and the 1.0-ha new re-injection well pad [not sure what this word is?]; the repair/drilling of old/new wells; and management of additional liquid wastes and air emissions associated with the operation of the 20MW geothermal power generating capacity. b) Social Issues There are no significant social issues associated with the project. The project will not cause involuntary resettlement or displacement of livelihood as there will be no land acquisitions involved and all land developments are confined within the existing geothermal field. The other social issues usually associated with development projects in the Philippines such as the potential presence of indigenous population and community acceptance are also not a concern. The Southern Negros Geothermal reservation is not known to be an ancestral home of indigenous cultural minorities. The local population consists of Cebuanos who are the dominant mainstream ethnolinguistic group in the Visayas and Mindanao. The project is also welcome by local residents as it will provide them additional benefits in terms of subsidized power rates, livelihood support, environmental, health and other social development interventions. In terms of gender issues, the project is not expected to significantly alter gender equity patterns in employment but it is expected to positively contribute gender equity among local agricultural populations through the additional social forestry programs and other community development efforts. c) Environmental Issues Since the project is basically an optimization of the existing geothermal production field, the scale of activities and new processes involved is expected to be small compared to a full blown geothermal power development. The likely environmental issues include: increased sedimentation from the civil work activities; the handling and disposal of wastes, which include drilling wastes, spent geothermal fluids or brine, cooling tower blow down and sludge; and, the air quality impact of the additional air emissions from the new plant, particularly hydrogen sulfide (H2S). The EA report

- 15 -

provided comprehensive assessments of the project’s environmental impacts. The Environmental Management Plan (EMP) contained in the EA report is also comprehensive and have adequately addressed all issues of concern. In terms of air quality impacts, the EA predicts that the expected ambient H2S concentrations with the new plant fully operating will still be below the 0.07ppm government standard for residential areas. Impacts on water quality will be negligible and will likely be only in the form of increased sedimentation from civil works as all liquid wastes will be re-injected back to the geothermal reservoir through a Zero Discharge Scheme (ZDS). The provision of steel casing of the wells to up to 1,000 m also ensures that the groundwater aquifer is not contaminated by geothermal brine. Finally, the project will not adversely affect the forest and natural habitat as the 4.1 ha total area to be opened up consist mainly of built-up lands and logged-over grasslands, all within the existing geothermal production field. d) Public disclosure Although the project is not required by the government to undergo a consultation process since it is exempted from the Philippine environmental impact statement system, PNOC-EDC conducted consultations with local residents and government officials. It has secured endorsements of the project from the Negros Oriental Provincial Development Council and the Central Visayas Regional Development Council. Copies of the full EA report were provided to the municipal and the provincial governments while an EA summary was published at the company’s website. The same EA report was disclosed in the World Bank’s Infoshop. e) Potential Legacy Issues The Bank’s due diligence work was expanded to include existing projects or activities of PNOC- EDC within the geothermal field that are not part of the Project but may have legacy or outstanding issues which could be linked to the Project or which may pose reputational risks to the Bank. The Task Team’s site inspection and review of documents on environmental and social performance have not found any outstanding issues associated with these projects. Palinpinon I and II have been in compliance with the national ambient air and water quality standards and were strictly following government regulations in the handling of hazardous wastes. In terms of social programs, these earlier projects have continued to provide development support for the surrounding communities. The only potential source of issues, if any, is the ongoing resettlement program, which PNOC-EDC is implementing in collaboration with the Municipality of Valencia as part of the earlier Palinpinon I and II projects (not part of this Project). Nevertheless, given the excellent track-record of PNOC-EDC, no problems are anticipated. The program has so far conformed to the Bank-prescribed processes. Its implementation will be monitored as part of the compliance monitoring for the Nasulo project. f) Management Measures and Institutional Arrangements The EMP submitted by PNOC-EDC has adequately addressed all issues of concern. As required in the ERPA, PNOC-EDC will be responsible for carrying out all the social and environmental management measures that it has committed to undertake. The third party CER auditor will be tasked to monitor the implementation of social and environmental management plans of PNOC-EDC while the Bank will also undertake regular supervision of safeguard implementation and

- 16 -

compliance. For the purpose of compliance monitoring, the Bank and the PNOC-EDC shall agree to focus on a smaller subset of issues critical to the project. A tentative list of issues and their corresponding management measures and indicators is provided in Annex 10, Table 1. To facilitate compliance monitoring and audit, the PNOC-EDC will be required to submit semi-annual safeguard compliance report to the Bank. 4. Policy Exceptions and Readiness No policy exceptions are being requested.

- 15 -

TECHNICAL ANNEX 1: POWER SECTOR BACKGROUND

Capacity fuel mix

Coal-fired plants remain

to be the dominant type

of power generation in

the country. As of end-

2003, installed capacity

of coal-fired power plants

accounted for 26% of the

total generating capacities

in the country or 3,958

MW. Most of these coal-

fired power plants are

located in Luzon,

accounting for 32% of the

total installed capacity in

Luzon. Oil-based power

plants comprise 24% of the capacity mix.

Hydroelectric power has the highest contribution among indigenous resources, with a share of

19% to total capacity. In Mindanao grid, hydroelectric power facilities represent almost 60% of

the capacity mix. Since the commissioning of natural gas in 2002, its share to the capacity mix

increased to 18% (2,763 MW) and even higher at 23% among the Luzon-based power generating

facilities. Geothermal, which is dominant in the Visayas, contributes about 13% or 1,932 MW of

the capacity mix.

Power generation fuel mix

The country’s total electricity generation

in the main grids in 2003 is estimated at

52,863 GWh, indicating 9.1% increase

compared to its 2002 level of 48,647

GWh. Coal remained as the highest

contributor of electricity and posted a

generation of 14,517 GWh or 28% of the

total, although its volume was reduced

by 10% compared to its 2002 level of

16,125 GWh. This can be attributed to

several factors: more diversified

utilization of existing generating facilities in Luzon with the full commercialization of natural

gas for power and more production of oil-based plants in Visayas particularly in Cebu with the

operational problems of coal-fired power plants.

Installed and Dependable Capacity by Source, 2003

in MW

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Coal Oil-based Hydro NatGas Geo

Installed Dependable2 6 .2 %

2 3 .8 %

19 .0 %18 .3 %

12 .8 %

2 7.5 %

2 3 .7 %

16 .9 %

2 0 .2 %

11.7 %

Power Generation, 2003

Coal

27%

Oil-based

14%

Geothermal

19%

Hydro

15%

Natural Gas

25%

Total Generation = 52,863 GWh

- 16 -

Visayas Power Generation Mix

Power generation in Visayas rose from its 2002 level of 6,098 GWh to 8,764.5 GWh in 2003, an

increase of 44%. While coal generation is predominant in Luzon, geothermal is the largest

electricity contributor in Visayas and accounts for 72.6% (6,361 GWh) of the total mix in the

region. Oil-based plants contributed 2,205 GWh or 20.8% of the total mix, about 33.5% higher

than its previous 2002 level of 1,652 GWh or 27% of total. The remaining portions were

contributed by coal and hydro resources, which only registered meager shares of 166 GWh

(1.9%) and 32 GWh (0.4%), respectively.

Visayas Power Grid Supply and Demand

The projected demand for the region is forecast to grow from its estimated value in 2005 of 1,113

MW to 1,383 MW by 2009 and 1,849 MW by the end of the planning period. This indicates an

average annual growth rate of 5.7%. To ensure a more credible supply expansion plan, DOE’s

2004 Power Development Plan considers both the interdependence and transmission constraints

among sub-systems of the Visayas region. One of the identified long-term approach for Visayas

power development is to ensure optimization and sharing of indigenous resources among the sub-

grids through strengthening and upgrading of the various transmission lines connecting the five

individual island grids.

Projects which are already being undertaken with firm financial backing are considered as

committed plants. About 250 MW of the total requirements have been committed for the next 4

years. Among the committed power plants are the NPC’s transfer of 110 MW Pinamucan Diesel

plant to Panay in 2005 and the proposed 20 MW Nasulo Geothermal Power Project (also known

as Palinpinon Optimization Project) to be commissioned in 2007.

0

400

800

1200

1600

2000

2400

Req'd Cap. Add. 0 0 0 100 0 0 150 100 100 150

Committed Cap. 151 0 84 20 0 0 0 0 0 0

Existing 1435 1435 1410 1410 1410 1410 1366 1366 1366 1366

Peak 1113 1170 1238 1308 1383 1463 1550 1644 1742 1849

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

MW

SUPPLY DEMAND PROFILESUPPLY DEMAND PROFILEVisayas, 2005 – 2014

Transfer of Pinamucan DPP(110 MW), Guimaras DPP (3.4 MW), Mirant DPPs (37.5)

N. Negros Geo, Palinpinon Geo (60MW), Talisay (30 MW, net 24 MW)

Bais Bioenergy (25 MW, net 20 MW)

Additional Capacity Needed

Retirement

Cebu LBGT – 55 MW (2011)

- 17 -

Renewable Energy Policy Framework

This policy framework embodies the DOE’s objectives, goals, policies and strategies as well as

programs and projects to further develop the RE sector within the perspective of the sector’s

supply and demand prospects and current stage of development given its critical role in the

country’s energy future. It is the government’s policy to facilitate the energy sector’s transition

to a sustainable system with RE as an increasingly prominent, viable and competitive fuel option.

The shift from fossil fuel sources to renewable forms of energy is a key strategy in ensuring the

success of this transition. Moreover, current initiatives in the pursuit of this policy are directed

towards creating a market-based environment that is conducive to private sector investment and

participation and encourages technology transfer and research and development. Thus, current

fiscal incentives provide for a preferential bias to RE technologies and projects which are

environmentally sound.

Energy Sector Objectives, RE Goals, Policies and Strategies

Energy Sector Objectives

RE Goals

RE Policies and Strategies

Ensure sufficient, stable,

secure, accessible and

reasonably-priced energy

supply

Pursue cleaner and efficient

energy utilization and clean

technologies adoption

Cultivate strong partnership

and collaboration with key

partners and stakeholders

Empower and protect welfare

of various energy publics

Increase RE-based capacity by

100% by 2013

Be the number one

geothermal energy

producer in the world

Be the number one

wind energy producer

in Southeast Asia

Double hydro

capacity by 2013

Expand contribution

of biomass, solar and

ocean energy by 131

MW

Increase non-power

contribution of RE to the

energy mix by 10 MMBFOE in

the next ten years

Diversify energy mix in favor of

indigenous RE resources

Promote wide-scale use of RE as

alternative fuels and technologies

Transform Negros island as a model

of RE development and utilization

Make the Philippines a

manufacturing hub for PV cells to

facilitate development of local

manufacturing industry for RE

equipment and components

Encourage greater private sector

investments and participation in RE

development through market-based

incentives

Establish responsive market

mechanisms for RE-generated

power

Formulate an effective management

program for fuelwood utilization

with the view of reducing

environmental impact

- 18 -

Geothermal Power Generation

The Philippines remains the world's second largest user of geothermal energy for power

generation with 1,931 megawatts (MW) of installed capacity. In 2003, geothermal power plants

generated a total of 9,419 gigawatt-hours (GWH) of electricity, accounting for 19% of the

country's total electricity requirement.

Geothermal Potentials. With only 1,931 MW installed out of 2,047 MW proven geothermal

reserves and 4,790 MW potential reserves, there are obviously plenty of opportunities for

expansion and private sector involvement. The primary emphasis will necessarily be to complete

on-going geothermal projects such as the expansion and/or further development of major known

geothermal fields – expansion project in fields Bacon-Manito in Albay/Sorsogon, optimization

projects including this Project in Negros Oriental and in Mt. Apo in Davao, and the development

of Cabalian project in Southern Leyte. Private sector investment in said projects, which are

located in areas covered by service contracts between the DOE and PNOC-EDC, could be

realized through venture arrangements with PNOC-EDC and participation in the recently

launched First Philippine Geothermal Contracting Round. Private companies may also consider

investing in nonpower utilization of geothermal energy.

- 19 -

TECHNICAL ANNEX 2: MAJOR RELATED PROJECTS FINANCED BY THE BANK AND/OR OTHER

AGENCIES

The most directly related project is the Bank-GEF financed Rural Power Project, the first phase of

an Adaptable Program Loan (APL) aimed at supporting reforms and priority investments in the

rural power sector, and removal of barriers for renewable energy development. The electrification

investments are for: (1) grid-connected electric cooperative (EC) subprojects; and, (2)

decentralized electrification. The first type of subprojects will improve power supply systems '

safety, reliability, efficiency and power service quality for existing customers, through

rehabilitation and capacity upgrades of the existing supply system; remove supply system

constraints, encourage institutional development of ECs, and, improve employee productivity,

safety, and, efficiency of customer service provision. The second type of investments will be in

small power generation, decentralized grids, and stand-alone renewable energy technologies (RET)

systems, most notably photovoltaic (PV) systems. The Partial Credit Guarantee Fund component

will help establish, and provide grant funds to partially cover loan losses incurred in the provision

of loans to RET purchasers, and suppliers. This component is funded by a United Nations

Development Program (UNDP)-Global Environment Facility (GEF) grant. Finally, the third

component will support the DOE, Energy Regulatory Commission, the Development Bank of the

Philippines, participating financial intermediaries, and participating enterprises in reducing market

barriers for the commercialization of RETs, by building capacity of concerned public, and private

sector entities. Investment risks would be reduced through strong project development, appraisal,

procurement, and supervision of RET subprojects, and, by supporting implementation policies on

energy tariffs and subsidies, and on regulation, and planning. This component is funded by a Bank-

GEF grant. Other related completed, ongoing or planned electrification projects are shown in the

following table:

Sector Issue

Project

Latest Supervision

(PSR) Ratings

Implementation

Progress (IP)

Development

Objective

(DO)

Implement Phase 1 of APL with overall

aim of supporting reforms and priority

investments in rural power sector and to

remove barriers for renewable energy

development

Implementation of a partial credit

guarantee program and related capacity

building activities for selected electric

cooperatives to promote energy efficiency

and system loss reduction

Bank/GEF financed Rural

Power Project

GEF-financed Electric

Cooperative System Loss

Reduction Project

S

S

S

S

---------------------------------------------------

S = Satisfactory

- 20 -

TECHNICAL ANNEX 3: RESULTS FRAMEWORK AND MONITORING

A detailed results and monitoring framework is presented in the Project Design Document.

- 21 -

TECHNICAL ANNEX 4: DETAILED PROJECT DESCRIPTION

Overview. The Southern Negros Geothermal Production Field (SNGPF) is located in Negros

Island in central Philippines, and consists of the Palinpinon and Dauin geothermal fields. The

Palinpinon Field is divided into 2 geographical areas, namely, the operating fields of Palinpinon

1 and Palinpinon 2. The SNGPF at present has a total combined capacity generation of 192.5

MW. The combined electrical power produced from the 112.5 MW capacity Palinpinon I power

plant and 80 MW (aggregate) Palinpinon II power plants supply the island of Negros, Panay and

Cebu. Palinpinon I started commercial operations in 1983 and twelve years later, Palinpinon II

went into commercial operation starting with the 20 MW Nasuji Power plant, followed by the

2x20 MW Sogongon and 20 MW Okoy-5.

The proposed Project will “optimize” steam utilization at the Nasuji area within the Palinpinon-2

steamfield in Southern Negros by tapping excess steam for additional power generation capacity

amounting to 20 MW1. The additional capacity will significantly contribute to meeting the

growth in energy demand in the Visayas Grid in the immediate term.

Resource Assesment. Output measurements made of the production wells in the Palinpinon 2

geothermal field, up to 2001, indicated excess available steam supply equivalent to around 21

MW with the largest excess steam of approximately 10 MW coming from the Balasbalas area.

PNOC-EDC management commissioned in early 2002 an assessment of the excess steam

available to support the proposed project, an additional 20 MW power plant in the Palinpinon 2

sector.

The components of the resource assessment study included estimation of volumetric stored heat

to ensure adequate thermal capacity, decline curve analysis using lumped parameter modeling to

assess pressure drawdown of the new plant, and reservoir pressure trend analysis for the

Palinpinon-2 field. Reservoir pressure measured in the Palinpinon-2 field in 1990 started at about

11 Mpag that then stabilized in early 2002 at 6 Mpag2. The study thus confirmed that the field

can support the additional fluid extraction needed for commercial operation for 25 years of a

new geothermal power plant of up to 40 MW.

Development Strategy. The essence of PNOC-EDC’s strategy in the development of the

additional 20 MW power plant is to lower construction and operating costs by locating the power

plant adjacent to existing facilities. This strategy would lower the cost of piping, civil works

and interconnection to Transco’s transmission lines. Operating and maintenance cost would also

be reduced, since the same manning complement that operates and maintains the existing facilities

could also be made responsible for maintaining the facilities of the new plant.

1 Although the steam field for the proposed plant is also in the Nasuji Sector, the new plant will be called “Nasulo

GPP” to avoid confusion with the existing 20 MW Nasuji GPP. Nasulo is the name of the nearby fault. 2 Measurements made since then up to 2005 showed the pressure remaining stable at about 6 MPag. This supports

the decision to allow a further 1 MPa drop due to the addition of the Nasulo PP, without risk of affecting the output

of Palinpinon-1.

- 22 -

Figure 1

1 x 20 MW Nasulo Geothermal Project

DEVELOPMENT PLAN

1 10 7 852P-4

1 121 957

D-6

1,02

5,90

0 N

1,02

6,10

0 N

1,02

6,30

0 N

SOUTH PAD

MIDDLE PAD

NP

C

PIP

ELIN

E

TO N PC CO OLI NG T OW ER

UNLOA

D

TO

CREE

K

TO O

KOY-6

THERMAL PO ND

S U

M P

CE NT ER

CONT ROL

NA SUJI

MIDDLE PAD

S U

M P

NORTH PAD

ADDITION AL WELL

EXISTING 20 MWe

NASUJI POWER PLANT

(EL = ±1090m)

A D D IT ION A L 20 M We

P OWER P LA N T

- 23 -

Project Components-. The project includes the following components: (1) development of a 20

MW geothermal field including the drilling of 1 production well (already completed) and 2

reinjection wells, as well as the construction of the corresponding fluid collection and reinjection

system; (2) construction, installation and commissioning of a 1 x 20 Geothermal Power Plant with

H2S gas abatement facility; and (3) construction of a switching station in Nasuji to connect to

Transco’s 138 kV transmission line.

Fluid Collection and Reinjection System. The FCRS comprises mainly of a piping system with

pressure relieving and reinjection functions. The two-phase fluid from the geothermal production

wells will be collected and directed to the separator vessel. The two-phase fluid shall then go

through separation process where the steam vapor and liquid are separated. The separated steam is

channeled to a piping system for power plant steam requirement. Separated water (brine) is re-

injected back to the reservoir.

The investment cost of the FCRS includes the cost of tapping to the existing two-phase branch line

and shorter length two-phase header, the fabrication of a 20 MW capacity separator, rock muffler,

and silencer, the protection devices, the piping system for both steam and water line and the control

system. The development cost includes the cost of drilling one production well to be hooked-up to

the south production pad, to sustain the over-all steam requirements of both the existing 20 MW

Nasuji GPP owned by NPC and the proposed 20MW Nasulo GPP.

Power Plant. The power plant component includes the civil works, turbine, generator,

condenser, cooling system and gas extraction system and a Hydrogen Sulfide (H2S) abatement

facility (gas abatement system). Once operational, the plant is expected to generate about 150

GWh and mitigate about 123,000 tCO2 annually. The schematic diagram of the plant is shown

below:

- 24 -

Project Implementation. PNOC-EDC is responsible for the implementation of the Project.

PNOC-EDC drilling rigs and personnel shall be used to drill the required wells assisted by Drilling

Technical Service Contracts. The engineering design of the fluid collection and reinjection system

has been done by PNOC-EDC but actual construction of the system shall be bidded out. The power

plant and sub-transmission system shall be constructed under two separate turnkey contracts.

By the end of the 2nd

quarter of 2005, PNOC-EDC will commence the bidding process for the

construction of the fluid collection and reinjection system, the power plant and the transmission

line. Construction of the FCDS is expected to start 4th

quarter of 2005 while construction of the

power plant and sub-transmission system are expected to start in December 2005. Commercial

operation is targeted for December 2007. PNOC-EDC will drill the additional required production

well in Nasuji after the commissioning of the power plant to further augment the steam supply

from existing wells. Make-up production wells will be drilled at approximately 10 year intervals

during the commercial operation of the plant.

Power Plant Operation. The power plant will be operated by qualified PNOC-EDC staff who have

undergone comprehensive training in the various aspects of plant operation and maintenance.

Provision of training to PNOC-EDC staff prior to and during plant commissioning will be a

required part of all bids for the power plant contract.

Electricity Sales. The electricity output will be sold initially to the Wholesale Electricity Spot

Market (WESM). It is uncertain at this point as to if and when bilateral contracts could be

concluded for some or all of the power produced.

- 25 -

TECHNICAL ANNEX 5: PROJECT COSTS

Cost Estimates. The base project cost (in September 2002 prices) is estimated at

P1,616.37 million (US$31.08 Million); the total cost (including physical and price

contingencies), is P1,742.76 million (US$33.51 million), with a foreign component of

US$26.44 million. Physical contingencies represent 6.5% of the base cost while price

contingencies for the local and foreign components was estimated at 4.3% and 1.1%,

respectively. The steamfield portion of the project is exempt from taxes. For other

project components, VAT is assumed at the current rate of 12%. Table 4.1 summarizes

the cost estimates for the project.

Table 4.1 Project Cost Summary

Steamfield Dev't Costs - 105.12 105.12

Consultants Services - - -

Fluid Collection and Reinjection System 1.64 101.54 194.40

Power Plant 28.24 24.30 1,619.97

Switchyard and Transmission Lines - - -

Land Acquisition - - -

Administration - 24.04 24.04

Total Project Cost 29.89 255.00 1,943.53

Price Contigencies 0.27 4.08 19.32

Physical Contigencies 1.58 17.23 106.30

TOTAL 31.73 276.31 2,069.16

Exchange Rate, PHP:US$ 56.50

Project Component

Foreign

Component

(Million US

Dollars)

Local

Component

(Million

Philippine

Total (Million

Philippine

Pesos)

- 26 -

TECHNICAL ANNEX 6: IMPLEMENTATION ARRANGEMENTS

The detailed implementation arrangements will be presented in the Netherlands Clean

Development Facility (NCDF) Emission Reductions Purchase Agreement (ERPA) to be signed

between PNOC-EDC and International Bank for Reconstruction and Development, as

trustee of the NCDMF.

- 27 -

TECHNICAL ANNEX 7: FINANCIAL MANAGEMENT AND DISBURSEMENT ARRANGEMENTS

This annex is not required for CF projects.

- 28 -

TECHNICAL ANNEX 8: PROCUREMENT

This annex is not required for CF projects.

- 29 -

TECHNICAL ANNEX 9: ECONOMIC AND FINANCIAL ANALYSES

Project evaluation was conducted by the Bank largely based on the desk review of the available

data and information as well as field visits and meetings with PNOC-EDC.

Assumptions:

Power sales – assumed to be about 150 GWh annually. Although the Project will be a

merchant plant prior to the conclusion of bilateral contracts for the power sales, the risk

of substantially lower market share is low, in light of DOE’s projected power demand for

the Visayas grid and the lower cost of geothermal power as compared with such

alternatives as diesel-fuelled power at the margin.

Power Price – based on NPC’s current power tariff for the Visayas grid at P3.2646/kWh.

The results of sensitivity analysis indicated that the break-even tariff is about P2.4/kWh,

thus allowing for a 26% margin to cover the downside risk of power price.

Project cost –PNOC-EDC’s cost estimates were based on prices in contracts recently

placed by the Company for similar works and estimates by its feasibility study

consultants. For prudence, the base case for project returns are based on cost estimates

higher than those of PNOC-EDC, as recommended by the Bank’s independent

consultant, including higher unit cost of well drilling ($1.5 million per well) and two new

reinjection wells. Details of the project cost are in Annex 5.

Operating and maintenance costs – Power plant O & M costs have been assumed to be

$35/kW/yr in feasibility study, along with steam field maintenance costs budgeted at

around $300,000 per year, and these estimates are considered by the Bank’s geothermal

consultant to be appropriate. In addition, allowance has been made for the drilling of one

new production well every ten years at a cost of about $1.5 million.

Project financing – The Development Bank of the Philippines (DBP) already approved a

15-year loan of P1.4 billion (US$24.8 million, at assumed exchange rate of P56.5 to

US$1) to PNOC-EDC, with the requirement that the Project sponsor will endeavor to

secure carbon credits under this Project. The interest rate of the above DBP loan will be

8% per annum for the first ten years, and increased to 9.5% per annum for years 11 to 15.

Additional financing charges include front-end fee of 1%, commitment fees of 0.75% and

gross receipts tax of 5%. Grace period is 5 years, and repayment will start in year 6. No

problem is expected for PNOC-EDC to finance the balance of the project costs, about

US$10.7 million, from its internal cash generation (in addition to financing the sunk costs

of about US$1.1 million for steamfield development).

Emission Reductions credits -- The Emission Reductions Purchase Agreement (ERPA),

to be negotiated between PNOC-EDC and the Bank (acting as trustee for NCDF),

provides for a price of about $5.6 per tCO2e and target annual CERs of 88,000 tCO2e for

full-year of power plant operation until the year 2012. The exact amount of ERs eligible

for purchase is determined by a Baseline Study and by independent verification of actual

energy output each year after plant commissioning.

Project economic life – 25 years

Transmission loss -- 3.5 %

Depreciation -- straight-line method based on the following estimated useful lives of the

properties: (i) investments in producing properties: 30 years; (ii) buildings: 5 – 30 years;

- 30 -

(iii) exploration, machinery and equipment: 2 – 10 years; (iv) furniture, fixtures and

equipment: 3 – 10 years; (v) transportation equipment: 5 years; and (v) laboratory

equipment: 5 – 10 years.

Royalty/Income tax -- PNOC-EDC entered into seven geothermal service contracts with

the DOE, granting the Company the right to explore, develop and utilize the geothermal

resources, subject to sharing of net proceeds with the government. The net proceeds is

what remains after deducting the gross proceeds the allowable recoverable costs, which

include development costs, production and operating costs. PNOC-EDC remits 60% of

the net proceeds to the government, comprising royalty fees and income taxes.

Economic Analysis

The costs and benefits estimated for the calculation of both economic and financial rates of return

are assumed to be the same, except for the exclusion of taxes in the case of the economic rate of

return (ERR). The main project benefits will be derived from sales of power, while carbon credits

will contribute to additional revenues at the margin. The main project cost is related to the up-front

capital cost, while the operating and maintenance costs include, among others, replacement wells.

The ERR, estimated at about 15 % (in real terms), which is satisfactory.

Economic Rate of Return

(In Million Pesos)

Local Forex Local Forex

2005 152.66 92.43 2.28 179.51 426.89 - - - 426.89 - - (426.89)

2006 166.66 121.14 11.86 906.97 1,206.63 - - - 1,206.63 - - (1,206.63)

2007 24.22 - 9.50 725.66 759.37 3.43 7.91 11.34 770.71 30.67 100.13 (670.58)

2008 45.39 39.55 84.94 84.94 147.31 480.91 395.97

2009 28.99 39.55 68.54 68.54 153.36 528.50 459.96

2010 130.14 39.55 169.69 169.69 149.95 517.38 347.69

2011 17.14 39.55 56.69 56.69 140.83 487.60 430.91

2012 57.24 39.55 96.79 96.79 153.36 528.50 431.71

2013 17.14 39.55 56.69 56.69 149.95 517.38 460.69

2014 45.39 39.55 84.94 84.94 140.83 459.75 374.81

2015 113.74 39.55 153.29 153.29 153.36 500.66 347.37

2016 45.39 39.55 84.94 84.94 149.95 489.53 404.59

2017 17.14 39.55 56.69 56.69 140.83 459.75 403.06

2018 57.24 39.55 96.79 96.79 153.36 500.66 403.87

2019 17.14 39.55 56.69 56.69 149.95 489.53 432.84

2020 130.14 39.55 169.69 169.69 140.83 459.75 290.06

2021 28.99 39.55 68.54 68.54 153.36 500.66 432.12

2022 45.39 39.55 84.94 84.94 149.95 489.53 404.59

2023 17.14 39.55 56.69 56.69 153.36 459.75 403.06

2024 57.24 39.55 96.79 96.79 153.36 500.66 403.87

2025 101.89 39.55 141.44 141.44 149.95 489.53 348.09

2026 45.39 39.55 84.94 84.94 140.83 459.75 374.81

2027 28.99 39.55 68.54 68.54 153.36 500.66 432.12

2028 45.39 39.55 84.94 84.94 149.95 489.53 404.59

2029 17.14 39.55 56.69 56.69 140.83 459.75 403.06

2030 141.99 39.55 181.54 181.54 153.36 500.66 319.12

2031 17.14 39.55 56.69 56.69 149.95 489.53 432.84

2032 17.14 39.55 56.69 56.69 146.61 478.63 421.94

ERR 15.0%

YearInvestment Costs Operating Costs

Steamfield Power Plant

Subtotal Steamfield

Power

Plant Subtotal

Total

Costs

Energy

Sales,

GwH

BenefitsNet

Benefits

- 31 -

Financial Analysis

(a) Project Returns

The financial rate of return (FRR), without sunk costs, is estimated at about 13.1% (in real

terms), which is satisfactory. With the inclusion of sunk costs, the FRR would be reduced

slightly to 12.5%. The results of sensitivity analysis indicated that even under the low scenario of

15% lower net cash flows from operation, the FRR of 10.2% remains slightly above the project

entity’s weighted cost of capital of about 9.7%. The carbon credits, estimated at about $492,800

per year, totaling about $2.5 million during the 5-year period of 2008-2012, are not expected to

have a significant impact on the project returns (improving the FRR by 0.5%), although they

facilitate the project sponsor’s access to credit for this Project.

Financial Rate of Return

(in Million Pesos)

- 32 -

Steamfield Power Total CER Total w/

Calendar GWH Cash Plant Net Benefits Cashflow

Year Sales Flow Cashflow CashFlow w/ CER

2003 0.00 (40.23) 0.00 (40.23) - (40.23)

2004 0.00 (25.87) 0.00 (25.87) - (25.87)

2005 0.00 (163.59) (170.10) (333.68) - (333.68)

2006 0.00 (267.61) (859.78) (1,127.39) - (1,127.39)

2007 30.67 (4.58) (627.90) (632.48) (632.48)

2008 147.31 65.39 288.19 353.58 353.58

2009 153.36 86.34 301.66 388.00 27.84 415.84

2010 149.95 (17.38) 294.12 276.74 27.84 304.58

2011 140.83 88.76 273.80 362.56 27.84 390.41

2012 153.36 58.09 301.71 359.79 27.84 387.64

2013 149.95 95.62 267.72 363.35 27.84 391.19

2014 140.83 60.51 226.82 287.34 287.34

2015 153.36 1.59 241.55 243.13 243.13

2016 149.95 67.37 232.16 299.53 299.53

2017 140.83 61.85 214.09 275.94 275.94

2018 153.36 26.18 228.81 254.99 254.99

2019 149.95 41.13 222.09 263.21 263.21

2020 140.83 (24.24) 208.27 184.03 184.03

2021 153.36 54.72 227.25 281.97 281.97

2022 149.95 29.83 222.12 251.95 251.95

2023 140.83 38.21 208.30 246.51 246.51

2024 153.36 26.18 227.28 253.46 253.46

2025 149.95 7.23 222.15 229.38 229.38

2026 140.83 26.91 208.33 235.24 235.24

2027 153.36 37.48 227.31 264.79 264.79

2028 149.95 29.83 222.18 252.01 252.01

2029 140.83 38.21 208.37 246.58 246.58

2030 153.36 (26.66) 227.35 200.68 200.68

2031 149.95 60.07 222.18 282.25 282.25

2032 146.61 40.06 212.76 252.82 252.82

FRR with sunk costs 6.2% 13.7% 12.0% 12.5%

FRR without sunk costs 8.1% 13.7% 12.6% 13.1%

(b) Project Entity, PNOC-EDC

Recent Finances. PNOC-EDC has remained consistently profitable. During the period 2002 to

2004, its gross revenues increased steadily by 2% - 4% p.a. During the same period, its year-to-

year net income has been volatile. Its net income decreased by 82% in 2003 mainly due to a

47% increase in royalty/income tax and, to a lesser extent, an 11% increase in general and

- 33 -

administrative (G & A) costs. On the other hand, its net income increased sharply by 26 times,

mainly due to a considerable reduction (28%) of its operating costs and royalty/income tax

(38%). A summary of its income statements is presented below.

PNOC-EDC Income Statements (2002-2004)

2002 2003 2004

Actual Actual Estimated

Revenues 19,630 20,370 20,760

Less: Operating Costs 12,069 12,230 8,780

Gross Income 7,561 8,140 11,980

Less: G & A Costs 2,266 2,524 2,054

Operating Income 5,295 5,616 9,926

Less: Non-Operating Charges 3,631 4,234 4,712

Income before Other Charges 1,664 1,382 5,214

Less: Extraordinary Charges 0 0 507

Income Before Royalty/Tax 1,664 1,382 4,707

Less: Royalty/Income Tax 838 1,234 770

Net Income 826 148 3,937

Since 1997, PNOC-EDC has experienced a liquidity squeeze, mainly due to the substantial

mismatch between the terms of its power purchase and sales agreements. Specifically, its power

purchase agreements, under five build-operate-transfer (BOT) contracts with private IPPs, are

only 10 years, whereas its electricity sales to NPC are covered by a much longer term, 25-year

power sales agreements. Consequently, PNOC-EDC has to seek external financing in order to

pay part of the BOT obligations. In addition, in 2004, the Company reported a negative networth

for the first time due to changes in Philippine accounting standards for foreign currency

transactions that no longer allow the Company to report deferred recognition of foreign exchange

gains or losses, except for such conditions as a severe devaluation of a currency. As a result of

the write-off against retained earnings of the earlier capitalized foreign exchange loss, amounting

to P31.2 billion, its debt/equity ratio deteriorated substantially in 2004. Indeed, in recent years,

PNOC-EDC has not complied with the minimum financial performance covenants under earlier

Bank-financed projects, as follows:

Financial Covenants 2002 2003 2004

Actual Actual Estimated

Current Ratio (1.0 minimum) 0.63 0.83 0.92

Debt Equity Ratio (70% maximum) 76% 75% 119%

Debt Service Ratio (1.25 minimum) 1.01 0.92 0.87

Future Finances. PNOC-EDC has planned to implement a number of measures to improve its

future finances, including the following: (a) review its plans and programs for operating budget

and capital expenditures to identify controllable expenses for possible deferral and reduction; (b)

continues to undertake profitable projects to improve its cashflow position over the medium and

longer term; and (c) revive its plan to privatize 60% of its shares, with 40% targeted for sales to

strategic operators and 20% through IPO in the Philippine stock exchange. If successful, PNOC-

- 34 -

EDC’s future finances are expected to improve considerably, as indicated in the projected

financial ratios below, along with its projected income statements, cash flows and balance sheets

over period 2005-2009. However, the projected improvements would not be sufficient to allow

the Company to comply with the existing financial covenants for debt/equity ratio and debt

service coverage ratio. Accordingly, PNOC-EDC has planned to request the Bank to consider

amendment of the above financial covenants, viz to waive the above two financial covenants for

2005 and 2006, and to reduce the minimum debt service coverage ratio to 1 time, starting from

2007. In light of PNOC-EDC’s action plan to strengthen its finances, which is satisfactory, the

Bank is expected to respond positively to this request.

Projected Financial Ratios 2005 2006 2007 2008 2009

Current Ratio (1.0 minimum) 1.52 1.78 1.80 1.43 1.12

Debt Equity Ratio (70% maximum) 86% 76% 66% 55% 39%

Debt Service Ratio (1.25 minimum) 0.88 0.93 1.11 1.05 1.04

PNOC-EDC Projected Income Statements (2005-2009)

2005 2006 2007 2008 2009

Revenues 21,951 22,838 24,517 25,925 26,516

Less: Operating Costs 9,568 9,313 8,230 7,952 8,334

Gross Income 12,383 13,525 16,287 17,973 18,182

Less: G & A Costs 2,162 2,458 2,753 3,295 3,601

Operating Income 10,221 11,067 13,534 14,678 14,581

Less: Non-Operating Charges 3,972 2,973 3,054 2,184 1,333

Income before Other Charges 6,249 8,094 10,480 12,494 13,248

Less: Extraordinary Charges 0 0 0 0 0

Income Before Royalty/Tax 6,249 8,094 10,480 12,494 13,248

Less: Royalty/Income Tax 713 855 3,020 4,588 5,146

Net Income 5,536 7,239 7,460 7,906 8,102

- 35 -

PNOC-EDC Projected Cash Flows (2005-2009)

2005 2006 2007 2008 2009

CASH, BEGINNING 6,907 16,526 14,369 14,826 14,215

INFLOW

Internal Cash Generation 8,739 10,256 10,902 11,094 11,217

(Inc)/Dec - Working Capital 197 (542) (324) 85 (47)

Foreign Loan Drawdowns 2,823 5,530 1,581 1,878 20

Increase in Equity 12,500 0 0 0 0

FCDU Loan Proceeds 0 0 0 0 0

Other Long-term Liabilities 356 356 356 178 178

Deferred Royalty Fee due to DOE 375 328 376 446 564

Total Inflow 24,990 15,928 12,891 13,681 11,932

OUTFLOW

Explo. & Dev't. Costs 1,363 1,207 303 404 278

Investment in Oil/Gas Activities 0 0 0 0 0

Capital Expenditures 2,920 6,228 2,323 2,332 144

Deferred Interest 176 285 35 56 15

Principal Payment - BOT CCR Fees 6,472 5,984 3,318 228 72

Royalty Payments to DOE 200 200 211 257 271

Payment of PNOC Advances 0 0 0 0 0

Loan Repayments 3,739 4,943 4,614 8,011 10,905

Payment of FCDU Loans 500 0 0 0 0

Cash Dividends 0 0 0 746 791

Other Assets 1 (762) 1,630 2,258 (260)

Total Outflow 15,371 18,085 12,434 14,292 12,216

NET INFLOW (OUTFLOW) 9,619 (2,157) 457 (611) (284)

CASH, ENDING 16,526 14,369 14,826 14,215 13,931

- 36 -

PNOC-EDC Projected Balance Sheets (2005-2009)

2005 2006 2007 2008 2009

ASSETS

Cash & Temporary Placements 16,525 14,368 14,826 14,214 13,930

Trade & Other Receivables 4,133 4,282 4,594 4,857 4,964

Materials and Supplies 723 723 723 723 723

Due from Affiliates 3 3 3 3 3

Other Current Assets 2,919 2,919 2,919 2,919 2,919

Total Current Assets 24,303 22,295 23,065 22,716 22,539

Property & Equipment 10,198 15,973 17,673 19,303 18,603

BOT Power Plant 20,837 19,824 18,596 17,595 16,310

Investment in Oil/Gas Activities 153 153 153 153 153

Investment in Prod. Properties 13,189 13,280 17,776 17,602 18,075

Exploration & Dev't. Cost 5,217 6,315 1,810 1,898 1,096

Other Assets 2,460 1,597 3,126 5,283 4,922

Total Assets 76,357 79,437 82,199 84,550 81,698

LIABILITIES AND EQUITY

Accounts Payable 4,181 3,701 3,110 3,031 2,938

Short-term Loans 334 334 334 334 334

Income Taxes Payable 71 115 645 1,017 1,107

Royalty Payable 329 371 420 473 538

Due to Affiliates 177 177 177 177 177

Current Portion - BOT Lease Obligation 5,984 3,318 228 72 0

Current Portion –LTD 4,864 4,541 7,884 10,830 14,971

Total Current Liabilities 15,940 12,557 12,798 15,934 20,065

Long-Term Debt BOT Lease Obligation 3,194 199 300 298 0

Long-Term Foreign Loans 43,925 45,660 40,098 31,788 17,322

Deferred Royalty Due to DOE 1,470 1,598 1,763 1,952 2,244

Other Long-term Liabilities 1,711 2,067 2,423 2,601 2,779

Deferred Credits 1,424 1,424 1,424 1,424 1,424

Total Long-Term Debt 51,724 50,948 46,008 38,063 23,769

Stockholders' Equity

Capital Stock 15,000 15,000 15,000 15,000 15,000

Paid-in Capital in Excess of Par 7,500 7,500 7,500 7,500 7,500

Donated Capital 423 423 423 423 423

Retained Earnings (14,230) (6,991) 470 7,630 14,941

Total Stockholders' Equity 8,693 15,932 23,393 30,553 37,864

Total Liabilities & Equities 76,357 79,437 82,199 84,550 81,698

- 37 -

TECHNICAL ANNEX 10: ENVIRONMENTAL AND SOCIAL SAFEGUARDS POLICY ISSUES

Background

The proposed Project is part of the long term development of the Southern Negros

Geothermal Production Field (SNGPF) which is already host to the 112.5MW Palinpinon

I and the 80MW Palinpinon II geothermal projects. The Nasulo will add 20MW to the

present power generating capacity. It will utilize some of the existing facilities (e.g.,

roads, well pads, offices, staging areas, etc.) and build on the existing management

systems (including existing environmental and social programs) of SNGPF.

The Bank’s due-diligence work started, in March 2004, with the examination of Project

Identification Note (PIN). In June 2004, the Task Team met with PNOC-EDC’s Planning

and Field Operations groups and visited the project site. Subsequent meetings with

PNOC-EDC’s Environmental Management Division (EMD) and the Bank’s Social and

Environmental Specialists were held between July and August, 2004, and the Safeguards

Team reviewed the following documents:

1. 1983-Environmental Impact Assessment for the Development of Southern

Negros Geothermal Field

2. 1986-Environmental Compliance Certificate (ECC) Exemption for Pal I

3. Executive Order, vesting PNOC-EDC the administrative jurisdiction to the

watershed areas of the 133,000-ha Southern Negros Geothermal Reservation

4. 1991 Environmental Impact Assessment for 80MW Palinpinon II

5. Confirmation the ECC Exemption for Palinpinon II

6. Environmental Impact Matrix for Nasulo Project which PNOC-EDC

submitted to Development Bank of the Philippines (DBP)

7. 2001 SNGPF Preliminary Resettlement Plan

8. Update on the Resettlement Program

In August 20, 2004, a formal request for the preparation of the EA and other specific

information were forwarded to the proponent. The full EA report along with other

documents was submitted to the Bank’s Manila Office on December 17, 2004. The EA

report contains comprehensive discussions on the baseline environment, impact

assessment, environmental management plan (EMP). Also contained in the EA report are

the following documents:

1. Watershed Management Plan

2. Emergency Response Plan

3. Environmental Risk Assessment (ERA) Report

4. Abandonment Plan

5. Project Endorsements from Provincial and the Regional Development

Councils

6. Corporate Environmental Policy

Additional documents on the environmental and social performance of existing projects

were requested to provide information on potential legacy issues. The documents were

received on May 16, 2005.

- 38 -

Environmental Category

The project is assigned Environmental Category B based on the following considerations:

(i) the Project is an add-on to existing operations; (ii) the project design includes re-

injection of spent geothermal fluid back to the geothermal reservoir which avoids

discharge of brine into rivers and water channels while providing continuous recharge to

the geothermal reservoir; and, (iii) the project entity has a proven track record of good

performance in environmental and social safeguards, as shown in various environmental

awards it gets from both government and non-government entities.

Safeguards Policies Triggered

Of the 10 Bank Safeguards Policies, only the policy on Environmental Assessment

(OP/BP 4.01) is triggered. The entire Southern Negros Geothermal Production Field

(SNGPF) is covered by an Environmental Impact Assessment conducted in 1983 which

precedes the Philippine Environmental Impact Statement (EIS) Law. As such, all

development activities within the SNGPF (i.e., Palinpinon I, II and this project) are

exempted from the present Philippine EIS process. A certificate of exemption to the

Environmental Compliance Certificate (ECC) was secured from the National

Environmental Protection Council (NEPC) on April 29, 1986. However despite the

exemption, PNOC-EDC for its own purpose conducted a separate Environmental Impact

Assessment for the Palinpinon II project in December 1991. For this present project,

PNOC-EDC submitted a comprehensive EA report to comply with the Bank Safeguards

requirements.

The project is also subject to the Bank’s policy on Public Disclosure (BP 17.50).

Social Issues

There are no significant social issues associated with the project. The project will not

cause involuntary resettlement or displacement of livelihood as there will be no land

acquisitions involved and all land developments are confined within the geothermal field.

The rests of potential social issues usually associated with geothermal development in the

Philippines are discussed below:

Indigenous Peoples – Southern Negros is not a known habitat of indigenous people or

cultural minorities. The present residents in the project area are relatively new settlers

from the lowland areas who belong to the Cebuano ethno-linguistic stock, the largest

mainstream group in the Visayas and Mindanao area. There is also no evidence that the

area had been occupied by any indigenous people.

Public Disclosure – Although the project is not required by the government to undergo a

consultation process since it is exempted from the EIS system, PNOC-EDC conducted

consultations with local residents and government officials. It has secured endorsements

of the project from the Negros Oriental Provincial Development Council and the Central

Visayas Regional Development Council. Copies of the EA report were provided to the

- 39 -

municipal and the provincial governments while a summary was published in the PNOC-

EDC’s website.. Also, PNOC-EDC has been engaging the barangays, people’s

organizations, and settlers within the geothermal reservation during the past 10 years on

various issues, concerns, developments, and opportunities related to the geothermal field.

The Geothermal Field has an active Multisectoral Monitoring Team (MSMT), composed

of community representatives, LGUs, NGOs and PNOC-EDC. The MSMT holds regular

meetings to review environmental performance of the project. They are also regularly

apprised of the activities in the SNGPF.

Community Acceptance –The project is received well by the local communities as it is

viewed as an addition to the existing geothermal operations which is providing them

benefits. The key stakeholders of the project are the National Government of the

Philippines, the host Local Government Units and residents of Barangay Puhagan,

Municipality of Valencia and Province of Negros Oriental. The local governments and

residents will benefit from increased royalty receipts and other law-mandated funds from

the project. At present, local residents are already benefiting from the royalties and other

law-mandated funds from existing Palinpinon I and II projects in the form of subsidized

power rates (up to 100% of monthly household consumptions in host barangays),

livelihood support, environmental, health and other social development interventions.

Apart from these law-mandated benefits, PNOC-EDC has been organizing local

communities and providing them with alternative livelihood under its Watershed

Management Program. PNOC-EDC has developed very positive and close relationship

with the surrounding communities within and outside the geothermal reservation. This

was validated by the Bank’s Safeguards Team during the field visit and consultation with

the barangay leaders and representatives from the Puhagan Farmers’ Association in July

27-28, 2004.

Gender Issues – The Project is not expected to significantly alter existing gender equity

patterns. The employment profile in the project will generally reflect the differentiated

roles of men and women in the Philippine society, i.e. construction and drilling works

will generate more jobs for men while office works will generate jobs for women. It is

expected that field-based hiring will be skewed toward male workers. At present, women

account for only 3% of personnel in SNGPF but a much higher percentage (20%) at

PNOC-EDC’s Manila Office. The positive contribution to gender equity would likely be

coming from the company’s community development efforts. Women had been involved

in the company’s social forestry and livelihood projects. At present they account for

about half (45%) of the 745 members in the 17 farmers’ associations. They also tend to

be more active in the associations’ activities, taking on policy and decision making roles.

They already account for more than 60% of the associations’ officers. This Project

promises to increase community development efforts of the company as indicated in its

watershed management plan.

Environmental Issues

Since the project is basically an optimization of the existing geothermal production field,

the scale of activities and new processes involved is expected to be small compared to a

- 40 -

full blown geothermal power development. Only minimal incremental environmental

impacts are anticipated. The environmentally critical activities are: land clearing and civil

works involved in the preparation of the 1-ha power plant site, the 0.5-km access road

and the 1.0-ha new re-injection well pad; the repair/drilling of old/new wells; and the

operation of the 20MW additional generating capacity. The likely environmental issues

include: increased sedimentation from the civil work activities; the handling and disposal

of wastes, which include drilling wastes, spent geothermal fluids or brine, cooling tower

blow down and sludge; and, the air quality impact of the additional air emissions from the

new plant, particularly hydrogen sulfide. The EA report provided very comprehensive

assessments of the environmental impacts (e.g., geology, hydrology, water quality,

aquatic and terrestrial ecology, air quality and socioeconomics). It has identified and

addressed both minor actual impacts as well as low probability potential impacts. The

following are assessments of the critical environmental issues:

Air Quality- The major air pollutant emitted by geothermal power plants is hydrogen

sulfide (H2S). The air quality monitoring which PNOC-EDC installed for existing power

plants, showed that the average ambient level of H2S is 0.017 ppm which is well below

the 0.070 ppm government standard for residential area. (Note that the current

government occupational standard for H2S is 10 ppm while the WHO 24-hr guideline

value is 0.105ppm). Under the new Philippine Clean Air Law, the SNGPF is designated

as a “geothermal airshed”. The airshed concept of the Clean Air Law provides that

geothermal projects within the airshed have to comply only with the ambient standards

rather than the emission standards. The air quality study using AERMOD predicts that

emissions from the new power plant will result to a ground level concentration of

between 0.008 to 0.042 ppm. Hence, given the background concentration of 0.017 ppm,

the expected ambient H2S concentrations with the new plant fully operating will still be

well below the 0.07ppm residential area standard.

Water Quality -The impacts on water quality will be negligible and will likely be only in

the form of increased sedimentation from civil works. Contamination of the surface water

with geothermal brine is highly unlikely as PNOC-EDC has long adopted the zero

discharge scheme (ZDS) in all its geothermal power plants. Under ZDS, liquid wastes

from geothermal power generation consisting of (a) drilling wastes, geothermal brine and

cooling tower blowdown are injected into designated re-injection wells. The whole

system consists of a network of pipes, sumps, thermal ponds and re-injection wells. The

geothermal brine and cooling tower blowdown are channeled into the thermal ponds for

cooling before they are conveyed by gravity or pumped into the re-injection wells.

Drilling wastes are temporarily stored in sumps to allow solid particles to settle before

they are conveyed to the re-injection wells. The thermal ponds and sumps also serve as

temporary holding ponds in case of re-injection failure. Contamination of groundwater is

also unlikely as the sumps and thermal ponds are lined with impervious materials while

the wells are cemented and steel-cased up to a depth of 1,600 meters, effectively

preventing contact between the geothermal fluid and the potable water aquifer. The

reinjection system of the project will be integrated into the existing reinjection system of

Palinpinon II.

- 41 -

Land Use and Forest- The Project will not adversely affect the forest, as all development

activities will be confined within the existing development block which is mostly built-up

or grassland with isolated tree species. A tree inventory of the new areas to be opened

(i.e. the 1.0-ha reinjection wellpad and 500-meter access road) has counted a total of only

29 trees. All except two of these trees are pioneer tree species or the kind of trees that

grow on a logged-over or fallowed area. On the contrary, the continued implementation

of the company’s watershed management program is expected to preserve or enhance the

forest cover of the geothermal reservation.

Natural Habitat and Protected Areas- The associated infrastructure and civil works

activities are not expected to affect critical natural habitats. The 4.1 hectares of land to be

opened up is a logged-over or fallowed area. Project documents provided also indicate

that the project site does not fall within a protected area. The nearest protected area is the

Balinsasayao Twin Lakes which is roughly 3 km from the site.

Potential Legacy Issues from Palinpinon I and II

An expanded scope of due diligence was adopted by the Task Team in order to include

existing projects (Palinpinon I and II) or activities of PNOC- EDC within the geothermal

field that are not part of this Project but may have legacy or outstanding issues which can

be linked to this Project or which may pose reputational risks to the Bank. The Task

Team’s site visit and the review of documents on environmental and social program

performance have found no outstanding environmental and social issues associated with

these earlier projects. Environmental reports submitted by PNOC-EDC to the Department

of Environment and Natural Resources (DENR) indicate that the SNGPF projects have

been in compliance with the national ambient air and water quality standards and were

strictly following government regulations in the handling of a small volume of hazardous

wastes generated. An excellent performance on social development programs is also

noted. The Integrated Social Forestry (ISF) Program of Palinpinon I and II have

reforested a total 3,777 ha denuded areas since 1990 and has benefited more than farming

700 households in terms of livelihood projects. The only potential source of issues, if

any, is the ongoing resettlement program which PNOC-EDC is implementing in

collaboration with the Municipality of Valencia as part of the earlier Palinpinon I and II

projects. Nevertheless, given the excellent track-record of PNOC-EDC, no problems are

anticipated and the Task Team will continue to monitor the progress of implementation,

as elaborated below.

Palinpinon Resettlement Program - Settlements in the area have increased since

development activities started in 1976. Settlers were attracted to the economic

opportunities and improved accessibility of the area. Many of these settlers had built

informal dwellings on the roadsides, on landslide prone slopes and within the vicinities of

the project facilities. The resettlement program aims to transfer the whole village into a

new community which will be developed as part of the program. This will ensure their

safety while at the same time secure geothermal facilities. The program is being

implemented in collaboration with the Municipality of Valencia which is sharing the

program cost and the Gawad Kalinga of Couples for Christ who also reportedly offered to

- 42 -

provide additional assistance. The Municipality of Valencia supports the program, as the

resettlement of residents in one compact area would facilitate delivery of basic services.

So far the program have generally conformed to the Bank-prescribed processes. PNOC-

EDC had already drafted a resettlement policy framework. A survey of the affected area

counted 194 households and consultation with these affected households regarding the

relocation site and the compensation package to be provided is ongoing. The

implementation of the resettlement program will be monitored as part of the compliance

monitoring of the Project.

Institutional Capability of the Proponent

The project entity is a government-owned and controlled corporation which has a

mandate to develop the country’s geothermal resources. It has extensive experience in

geothermal power development and has developed and currently operates 5 geothermal

sites in the Philippines with a total generating capacity of more than 1,000 MW. Its

Environmental Management Division (EMD) has more than 20 years of experience in

conducting environmental impact assessments and in formulating and implementing

social and environmental management programs for geothermal projects. Staffed by more

than 20 office-based and close to 150 field-based personnel, EMD is responsible for

planning, formulating and implementing social and environmental management programs

for the company’s energy projects. As the administrator of the geothermal reservation,

the company has been implementing a comprehensive watershed management program to

ensure continued viability of the watershed. The program includes: (1) forest protection

or enforcement of forest laws, (2) reforestation or rehabilitation of denuded areas, and (3)

provision of extension services to the forest occupants. The company hires its own forest

guards to conduct frequent patrols within the reservation and prosecute violators of

Philippine forestry laws. Its Integrated Social Forestry (ISF) provides alternative

livelihood to the people who are dependent on the cultivation of public forest lands. As of

2003, the company has organized and supported more than 70 farmers associations

within its geothermal reservations.

Institutional Arrangements

The EMP contained in the EA report is comprehensive. The proponent will be

responsible for carrying out the social and environmental management measures that it

has committed to undertake in the EMP. For the purpose of compliance monitoring, the

Bank and the proponent shall agree on a smaller subset of issues critical to the project.

Table 1 below provides a tentative list of the significant issues and the proposed actions

needed to address them. The third party CER auditor will be tasked to monitor

implementation of these social and environmental measures while the Bank will also

undertake regular supervision of safeguard implementation and compliance. To facilitate

compliance monitoring and audit, the proponent will be required to submit semi-annual

safeguard compliance report to the Bank.

- 43 -

Table 1-Social and environmental issues and proposed management actions

Potential Adverse

Impact

Description Management Measures/Action Verifiable

Indicator

Schedule

A. Civil Works (Vegetation Clearing, Excavation, Slope Cutting)

Conversion of a

total of 2-ha shrubland/fallowed

swidden farms into

a new well pad and access road;

removal of some

tree stands.

The tree inventory

counted a total of 29 trees.

Secure a Special Land Use Permit and Tree Cutting Permit from

DENR

Replacement reforestation elsewhere within the area through

contract reforestation with existing

Farmer’ Association.

Implementation of the Watershed

Management Plan as contained in the EA Report.

SLUP; Tree

Cutting Permit; New reforestation

project; and

Livelihood project.

Before the

start of construction

Soil erosion and

possible sedimentation of

water channels

Sediments will mostly

come from the opening of 500-m access road and

1.0-ha reinjection

wellpad.

Slope stabilization through

mechanical (i.e., wattling, riprapping) and biological (i.e.

seeding or revegetation of exposed

slopes with fast growing cover crops)

Sediment/erosion control measures such checkdams, ripraps, gabions,

silt traps and drainage canals.

Proper disposal of earth spoils; Cut-and-fill method and

hauling/disposal of excess earth to the designated spoil disposal area.

Presence of

stabilized slopes erosion control

measures and,

Spoil Disposal Area.

During

construction roads and

wellpads

Possible increase

in migrant worker

population

This impact is not

expected to be significant

as the area was previously host to bigger

Pal I and Pal II projects.

Adoption of a local hiring policy

Coordination with local government officials and contractors on local

hiring policy

Local hiring policy

document;

Number of locally hired workers.

During

construction

Possible increase of settlements and

encroachments in

newly opened up

areas

The 500-m new access road may attract new

informal settlers and

swidden farmers.

Coordination with local government officials in the implementation and

enforcement of forestry laws

Continued implementation of forest

patrols with the involvement of

local communities

MOA with LGU or other evidences

of coordination

with LGU and

local communities

on forest

protection.

During and after

construction

B. Well Drilling and Testing

Deterioration of air

quality due to

release of Hydrogen Sulfide

Vertical well testing is 30

minutes long while

horizontal well testing will last for about 3

months.

Ducting of non-condensible gas to

improve air dispersion

NCG ducts

installed;

Levels of hydrogen sulfide

During well

drilling and

testing

Possible tempo-rary, localized

defoliation of

vegetation around the production

well pad area due

to release of hot steam during well

testing

The production wellpad where well testing will

occur is already a

developed area.

Proper positioning of silencer during 90-day horizontal discharge

away from critical areas

Silencer properly positioned;

Absence of

damage/defoliation of surrounding

vegetation.

During well drilling and

testing

Possible migration

of faunal species due to increase in

noise level at the

wellpad

Any disturbance will be

felt only within the existing production

wellpad which is located

in a relatively developed area.

Limit duration of vertical testing to

30 minutes.

Installation of silencer and/or rock mufflers during horizontal testing.

Silencer and rock

mufflers installed.

During well

drilling and testing

Possible contamination of

surface water from

liquid wastes (i.e. geothermal brine

and drilling

The existing production wellpad is equipped with

sumps to temporarily

contain drilling wastes and geothermal brine

during testing. The new

Use of sumps with impervious linings.

Provision of storm drainage, oil traps, ring drains and levees.

Sumps with impervious linings,

adequate drainage

and oil traps are provided at

wellpads; Water

During well drilling and

testing

- 44 -

Potential Adverse

Impact

Description Management Measures/Action Verifiable

Indicator

Schedule

wastes).

reinjection wellpad will

also be provided with sumps.

quality monitoring

report.

C. Steam Generation, Power Plant Operation, Transmission

Possible

contamination of water channels

from liquid wastes

(i.e., geothermal brine and cooling

tower blowdown)

The project will adopt a

zero discharge system (ZDS) where liquid

wastes will be reinjected.

The handling of project’s liquid wastes will be

integrated into the

existing Pal II ZDS.

In case of ZDS failure, regulated discharge and continuous water

quality monitoring should be done

to ensure that receiving water channels will remain within water

quality standards.

Incident reports;

Water quality monitoring report

and DENR report.

During ZDS

failure

Possible

contamination of

environment and groundwater from

cooling tower

sludge

Sludge handling system

already in place for Pal I

and II. The amount of sludge to be generated by

the project is only 1 drum

per year.

Cement fixing of cooling tower

sludge before entombment into the

cellar pit.

Sludge cellar pit

installed.

After every

PMS

Possible deterioration of air

quality due to the

release of Hydrogen Sulfide

The air dispersion study indicates that the ambient

H2S standard will not be

exceeded, given background levels and

stack height.

Management of geothermal airshed such that ambient standard is not

exceeded.

Regular ambient H2S monitoring

Ducting of non-condensible gas at cooling towers to improve

dispersion

Air quality monitoring report

to DENR; NCG

ducting installed at cooling towers

Operations Phase

Sudden decrease in employment and

livelihood

opportunities as construction

activities stops.

There are existing associations of local

residents organized under

the company’s Corporate Social Responsibility

(CSR) program that

receives livelihood support.

Provide livelihood support through existing cooperatives and

associations

Phase in new livelihood through

local government using DOE funds

and royalty

Livelihood projects of

farmers’ associa-

tions (FAs); Evidence of

PNOC-EDC and

DOE funds support to FAs.

Operations phase

D. Ongoing Palinpinon Resettlement Program

Resettlement of

about 200

households

The resettlement is joint

undertaking of the local

government, PNOC-EDC

and the local community,

using the law-mandated development funds that

the community receives

from Pal I & II.

Provide an updated Resettlement Action Plan

Conduct of monitoring and

evaluation; Submit to the bank M&E reports every six months

during the first three years.

Updated

Resettlement

Action Plan; M&E

Reports on

Resettlement; Developed

resettlement

community.

Before

ERPA

signing and

every six

months thereafter.

- 45 -

TECHNICAL ANNEX 11: PROJECT PROCESSING

Project Preparation Timeline

Project Schedule Planned Actual

PCN review 4/2005

Appraisal 6/2005

Negotiation 6/2005

Board/RVP approval N.A.

Planned date for effectiveness 10/2005

Planned closing date 12/31/2013

Bank Staff who worked on the project include:

Name Title Unit

Selina Shum Task Team Leader, Lead

Financial Analyst

EASEG

Francisco Fernandez-Asin Sr Financial Specialist ENVCF

Ernesto Terrado Consultant, Renewable Energy

Specialist

LCSFR

Frans Vandewydeven

Consultant, Goethermal

Specialist

Josefo Tuyor Environmental Specialist EASEN

Heather Batzel Counsel LEGCF

Jose T. Nicolas Social Development Specialist EASSD

Jonas Bautista Consultant, Environmental

Specialist

Carla Teresa Sarmiento Program Assistant EASEG

- 46 -

TECHNICAL ANNEX 12: DOCUMENTS IN THE PROJECT FILE

1. Project Idea Note (PIN)

2. Project Concept Note (PCN)

3. Project Design Document (PDD)

4. Letter of Intention

5. Letter of Approval

6. Feasibility Study

7. Environmental Impact Assessment (EIA)

8. Renewable Energy Policy Framework (DOE)

9. Philippine Energy Plan (DOE)

- 47 -

TECHNICAL ANNEX 13: Baseline and Additionality Analysis

1. Additionality

The Visayas sub-grid suffers from a deficit in electricity supply that is currently met by

barge-mounted diesel plants. Using an indigenous and renewable energy source the

proposed 20 MW project will obviate the need for equivalent capacity of fossil fuel-based

generation to meet the projected power shortfall in Visayas by 2006, thus mitigating GHG

emissions.

Prohibitive barriers that the Project faces are clearly identified in a transparent and

conservative manner using the “tool for the demonstration and assessment of

additionality”. Documented evidence is provided to support the argument that the Project

is not Business As Usual due to investment barriers. Other barriers in the form of

technology and prevailing practices also increase risk and further demonstrate that the

Projects successful implementation is depended on CDM assistance.

Main identified barriers are:

1. Cheaper cost of thermal energy had an impact in geothermal power developments

after privatization

Geothermal plants in the Philippines face stiff competition from cheaper thermal

technologies. Since privatization process was initiated by EPIRA (2001) no other

geothermal project has been developed in the Philippines. Geothermal technology is not

the least cost technology in the market. The arrival of the Natural Gas Pipeline to

Southern Luzon has marked the beginning of the development of large Natural Gas-fired

power plants.

Since the year 2001, three natural gas plants (Santa Rita, Ilijan and San Lorenzo) have

been constructed and put in operation by Independent Power Producers (totalling a

generation capacity of 2,700 MW). The last geothermal plant built in the Philippines was

Mindanao II which started operations in 1999 (that is before the EPIRA).

2. Concessional financing no longer available

Concessional financing is not longer available for geothermal developments after EPIRA.

For PNOC-EDC, Nasulo is the first geothermal project that is being financed by a local

bank. This loan has a higher rate and shorter tenor than the usual ODA loan that were

available before EPIRA (interest rates are Peso-denominated, at 8%-9.5% versus 1%-5%

for former geothermal plants; tenors of 15 years versus 25-33 years for former

geothermal plants).

Furthermore, PNOC-EDC has made public its intention to be privatized (March 2005)

which will make this type of financing permanently unavailable.

- 48 -

3. Barriers to investment in the Visayas

The Visayas Islands are not the preferred choice for investors. The last plant built in that

grid was in 1996. So for the last 7 years no other power plant has been built in that part of

the country. The current electricity shortages in the islands are now being mitigated by

transferring diesel power barges from Luzon.

4. Devaluation impact in financing creates a financing gap

Local financing has been achieved in form of a peso-denominated loan and the recent

devaluation of the local currency has created a financing gap that poses a serious problem

for project implementation. Project sponsor is turning to carbon finance to cover such

financing gap in the short run.

5. Barriers of Financing: Bank covenants linked to CDM income

The Bank has made the financing contingent to the project to attain CDM status. Without

CDM the project will not be financed. Loan agreements will be made available to the

Designated Operational Entity.

2. Baseline methodology

The consolidated baseline methodology for zero-emissions grid-connected electricity

generation from renewable sources (ACM0002) is applicable to the Project. The baseline

emission rate is the combined margin CEF for the grid, where:

the operating margin is defined as the generation-weighted average of all

generating sources excluding low-cost / must-run plants, where such plants must

constitute less than 50% of grid generation, and

the build margin is defined as the generation-weighted average emission factor of

either the 5 most recent or the most recent 20% of plants built or under

construction, whichever group’s average annual generation is greater.

The project is meets all the following conditions that are stated in the Baseline

Methodology:

The project supplies electricity capacity addition (20 MW) from a geothermal

source;

The project is not an activity that involves switching from fossil fuels to renewable

energy at the project site;

The electricity grid is clearly identified (as Visayas grid) and information is

available on the characteristics of the grid;

- 49 -

The operating margin for the Project is the generation-weighted average of all generating

sources, excluding hydropower and geothermal power plants for the three most recent

years in which grid data is available. The 3-year average is based on the most recent

statistics available at the time of PDD submission.

The BM is defined in the Baseline Methodology as the generation-weighted average

emission factor (tCO2/MWh) of a sample of power plants. The build margin is calculated

based on the 5 most recent or most recent 20% (of the system generation) of power plants

built. The BM emission factor will be calculated ex ante and be based on the most recent

information available at the time of PDD submission (Option 1 in the Baseline

Methodologies).

The baseline emission factor is the weighted average of the OM emission factor and the

BM emission factor. The default weight of the OM and BM emission factors (50%: 50%) is

to be used. The baseline emissions calculated for the project represent the approach

“emissions from a technology that represents an economically attractive course of action,

taking into account barriers to investment” as stipulated in the Baseline Methodology.

The combined margin CEF is estimated as 0.59 tCO2/MWh, being the average of the

operating margin (0.82 tCO2/MWh) and build margin (0.36 tCO2/MWh) CEFs. Neither

project emissions nor leakage arise from the Project.

3. Monitoring plan

In accordance with the consolidated methodology, the activity level, grid baseline emission

rates and barriers will be monitored.

For the grid baseline, the operating margin emission rate must be monitored and updated

yearly if there is not enough data to collect a 3-year average, based on the most recent

statistics available at the time of PDD submission. The Philippine Energy Plan (PEP)

2003-2014 provides 2001 and 2002 historical data for national fuel consumption by

generation type, but not for the individual grids. However, if the 2001 – 2003 data for the

Visayas grid can be obtained from PDOE prior to validation, monitoring of the operating

margin emission rate will not be necessary for the Project. As the Project is less than

60MW, monitoring of the build margin emission rate is not required.

The methodology requires that barriers and common practice be monitored for assessment

of project additionality at the time of renewal.

- 50 -

TECHNICAL ANNEX 14: STATEMENT OF LOANS AND CREDITS

Philippines

(April 30, 2005)

Active Projects

Project ID FY Project Name IBRD IDA GRANT Cancel. Undisb. Orig. Frm Rev'd

P079628 2005 PH - 2nd Women's Health & Safe Motherhood 16.00 0.00 0.00 0.00 16.00 0.00 0.00

P066076 2004 PH - Judicial Reform Support Project 21.90 0.00 0.00 0.00 20.68 -1.22 0.00

P070899 2004 PH - Laguna de Bay Institutional Strenghening 5.00 0.00 0.00 0.00 4.95 -0.05 0.00

P066532 2004 PH - GEF-Electric Cooprtv System Loss Redu 0.00 0.00 12.00 0.00 6.82 -5.18 0.00

P072096 2004 PH - GEF-Rural Power Project 0.00 0.00 9.00 0.00 8.67 0.43 0.00

P066397 2004 PH - Rural Power Project 10.00 0.00 0.00 0.00 10.19 -0.60 0.00

P075184 2004 PH - Diversified Farm Income & Mkt. Devt 60.00 0.00 0.00 0.00 59.17 2.50 0.00

P073488 2003 PH - ARMM Social Fund 33.60 0.00 0.00 0.00 29.75 13.97 0.00

P077012 2003 PH - Kalahi-CIDSS Project 100.00 0.00 0.00 0.00 85.15 26.50 0.00

P071007 2003 PH - Second Agrarian Reform Communities Dev 50.00 0.00 0.00 0.00 44.92 18.27 0.00

P069916 2002 PH - 2nd Social Expenditure Management 100.00 0.00 0.00 0.00 40.14 2.81 0.00

P069491 2002 PH - LGU Urban Water APL2 30.00 0.00 0.00 0.00 33.04 17.13 0.00

P066509 2001 PH - GEF-MMURTRIP-Bicycle Nwk 0.00 0.00 1.30 0.00 0.83 0.33 0.00

P057731 2001 PH - MMURTRIP 60.00 0.00 0.00 0.00 48.73 40.16 0.00

P059933 2000 PH - Coastal Marine 0.00 0.00 1.25 0.00 0.58 0.94 0.29

P039019 2000 PH - First Nat'l Rds Improve. 150.00 0.00 0.00 0.00 68.31 68.31 0.00

P048588 1999 PH - LGU FINANCE & DEV. 100.00 0.00 0.00 40.00 39.52 67.72 22.42

P057598 1999 PH - Rural Finance III 150.00 0.00 0.00 0.00 32.31 32.31 0.00

P004595 1998 PH - Community Based RESO 50.00 0.00 0.00 12.00 12.78 24.78 12.78

P004566 1998 PH - Early Child Development 19.00 0.00 0.00 0.00 1.86 1.86 -0.10

P004576 1998 PH - Water Districts Development 38.60 0.00 0.00 10.73 12.33 41.27 6.06

P004613 1997 PH - Water Resources Development 58.00 0.00 0.00 16.27 2.11 18.38 1.54

P004602 1997 PH - Third Elementary Education 113.40 0.00 0.00 20.10 19.80 39.90 19.80

P004611 1996 PH - Manila Sewerage II 57.00 0.00 0.00 20.90 6.49 27.39 0.94

P004406 1995 PH - ODS Investment Project 0.00 0.00 30.00 0.00 16.51 1.56 -6.23

Total 1222.5 0.00 53.55 120.00 621.63 439.48 57.50

Original Amount in US$ Millions Disbursements a/

Difference Between

Expected and Actual

- 51 -

Philippines

STATEMENT OF IFC’s Held and Disbursed Portfolio

April 30, 2005

(In US Dollars Millions)

Held Disbursed

FY Approval Company Loan Equity Quasi Partic Loan Equity Quasi Partic

2001 AEI 1.00 0.00 0.00 0.00 0.75 0.00 0.00 0.00

2002 APW Trade 0.00 0.00 0.65 0.00 0.00 0.00 0.65 0.00

Alaska Milk 0.00 0.62 0.00 0.00 0.00 0.62 0.00 0.00

2000 Asian Hospital 2.80 0.00 1.00 0.00 2.80 0.00 1.00 0.00

2002 Banco de Oro 20.00 0.00 20.00 0.00 0.00 0.00 20.00 0.00

1998 Drysdale Food 7.97 0.00 0.00 4.40 7.97 0.00 0.00 4.40

2002 Eastwood 17.22 0.00 0.00 0.00 17.22 0.00 0.00 0.00

2001 Filinvest 19.87 0.00 0.00 0.00 13.87 0.00 0.00 0.00

2004 Globe Telecom 20.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

1998 H&Q PV III 0.00 0.98 0.00 0.00 0.00 0.98 0.00 0.00

1989 H&QPV-I 0.00 0.18 0.00 0.00 0.00 0.18 0.00 0.00

1993 H&QPV-II 0.00 0.09 0.00 0.00 0.00 0.09 0.00 0.00

1992 Holcim Phil 0.00 1.97 0.00 0.00 0.00 1.97 0.00 0.00

2004 LARES 22.00 2.70 0.00 0.00 0.00 0.00 0.00 0.00

2000 MFI MEP 0.00 0.12 0.00 0.00 0.00 0.12 0.00 0.00

2001 MNTC 45.08 0.00 0.00 0.00 41.45 0.00 0.00 0.00

2003/04 MWC 30.00 14.96 0.00 0.00 0.00 14.96 0.00 0.00

2000 Mariwasa 11.84 0.00 3.20 0.00 11.84 0.00 3.20 0.00

Megaworld Corp 0.00 1.18 0.00 0.00 0.00 1.18 0.00 0.00

1993 Mindanao Power 0.00 3.41 0.00 0.00 0.00 3.41 0.00 0.00

1993 Mirant Pagbilao 12.00 10.00 0.00 0.00 12.00 10.00 0.00 0.00

2001 PEDF 1.50 0.00 0.00 0.00 0.75 0.00 0.00 0.00

1992 Pilipinas Shell 0.00 1.56 0.00 0.00 0.00 1.56 0.00 0.00

2000 PlantersBank 0.00 0.00 4.65 0.00 0.00 0.00 4.65 0.00

1998 Pryce Gases 15.04 0.00 0.00 5.82 15.04 0.00 0.00 5.82

2000 STRADCOM 11.53 0.00 4.00 0.00 9.13 0.00 4.00 0.00

2003 SVI 0.00 4.00 0.00 0.00 0.00 2.00 0.00 0.00

1995 Sual Power 21.72 17.50 0.00 54.52 21.72 17.50 0.00 54.52

1994 Walden Mgmt 0.00 0.03 0.00 0.00 0.00 0.03 0.00 0.00

1994 Walden Ventures 0.00 0.29 0.00 0.00 0.00 0.29 0.00 0.00

Total Portfolio: 259.57 59.59 33.50 64.74 154.54 54.89 33.50 64.74

Approvals Pending Commitment

Loan Equity Quasi Partic

2005 Cagayan Electric 15.00 0.00 0.00 0.00

2002 Eastwood 0.00 3.00 0.00 0.00

2005 NHMFC Asset Sale 30.68 2.68 0.00 0.00

2001 PEDF 4.50 0.00 0.00 0.00

2005 PLGIC 0.00 0.00 1.50 0.00

Total Pending Commitment: 50.18 5.68 1.50 0.00

- 52 -

TECHNICAL ANNEX 15: COUNTRY AT A GLANCE

East Lower-

POVERTY and SOCIAL Asia & middle-

Philippines Pacific income

2003

Population, mid-year (millions) 81.5 1,855 2,655

GNI per capita (Atlas method, US$) 1,080 1,080 1,480

GNI (Atlas method, US$ billions) 88.0 2,011 3,934

Average annual growth, 1997-03

Population (%) 2.2 1.0 0.9

Labor force (%) 2.8 1.1 1.2

Most recent estimate (latest year available, 1997-03)

Poverty (% of population below national poverty line) 37 .. ..

Urban population (% of total population) 61 40 50

Life expectancy at birth (years) 70 69 69

Infant mortality (per 1,000 live births) 28 32 32

Child malnutrition (% of children under 5) 32 15 11

Access to an improved water source (% of population) 86 76 81

Illiteracy (% of population age 15+) 7 10 10

Gross primary enrollment (% of school-age population) 112 111 112

Male 113 112 113

Female 111 111 111

KEY ECONOMIC RATIOS and LONG-TERM TRENDS

1983 1993 2002 2003

GDP (US$ billions) 33.3 54.4 78.0 80.6

Gross domestic investment/GDP 29.6 24.0 19.3 18.7

Exports of goods and services/GDP 21.6 31.4 48.9 48.3

Gross domestic savings/GDP 23.1 15.5 18.8 16.2

Gross national savings/GDP .. 18.6 26.1 26.8

Current account balance/GDP -8.3 -5.5 5.4 2.5

Interest payments/GDP 2.8 3.3 3.6 ..

Total debt/GDP 72.8 66.5 76.1 ..

Total debt service/exports 36.4 25.6 20.2 ..

Present value of debt/GDP .. .. 78.6 ..

Present value of debt/exports .. .. 134.6 ..

1983-93 1993-03 2002 2003 2003-07

(average annual growth)

GDP 2.1 3.9 4.4 4.5 4.2

GDP per capita -0.3 1.6 2.3 2.5 2.2

Exports of goods and services 6.0 4.8 3.6 3.3 5.9

STRUCTURE of the ECONOMY

1983 1993 2002 2003

(% of GDP)

Agriculture 22.4 21.6 14.7 14.5

Industry 39.2 32.7 32.5 32.3

Manufacturing 24.2 23.7 22.8 22.9

Services 38.4 45.7 52.8 53.2

Private consumption 68.6 74.4 69.1 72.3

General government consumption 8.3 10.1 12.1 11.4

Imports of goods and services 28.1 39.8 49.4 50.7

1983-93 1993-03 2002 2003

(average annual growth)

Agriculture 1.8 2.3 3.3 3.9

Industry 1.0 3.8 3.7 3.0

Manufacturing 1.9 3.5 3.5 4.2

Services 3.4 4.7 5.4 5.9

Private consumption 3.4 4.0 7.9 9.5

General government consumption 2.9 2.6 2.4 -2.8

Gross domestic investment 2.8 3.4 -3.5 4.8

Imports of goods and services 9.1 4.4 4.7 10.3

Note: 2003 data are preliminary estimates.

This table was produced from the Development Economics central database.

* The diamonds show four key indicators in the country (in bold) compared with its income-group average. If data are missing, the diamond will

be incomplete.

-20

-10

0

10

20

98 99 00 01 02 03

GDI GDP

Growth of investment and GDP (%)

Philippines

Lower-middle-income group

Development diamond*

Life expectancy

Access to improved water source

GNI

per

capita

Gross

primary

enrollment

-30

-20

-10

0

10

20

98 99 00 01 02 03

Exports Imports

Growth of exports and imports (%)

Philippines

Lower-middle-income group

Economic ratios*

Trade

Domestic

savingsInvestment

Indebtedness

- 53 -

Philippines

PRICES and GOVERNMENT FINANCE

1983 1993 2002 2003

Domestic prices

(% change)

Consumer prices .. 7.6 3.1 1.9

Implicit GDP deflator 14.2 6.8 4.9 3.7

Government finance

(% of GDP, includes current grants)

Current revenue .. 17.7 14.1 14.0

Current budget balance .. 2.3 -5.2 -1.3

Overall surplus/deficit .. .. -5.2 -4.6

TRADE

1983 1993 2002 2003

(US$ millions)

Total exports (fob) .. 11,375 34,383 35,414

Electronics/Telecom .. 3,551 18,583 19,053

Garments .. 2,272 2,391 2,348

Manufactures .. 8,729 31,181 1,252

Total imports (cif) .. 17,597 33,975 36,972

Food .. 714 1,384 2,378

Fuel and energy .. 2,016 3,273 3,899

Capital goods .. 5,610 13,532 12,889

Export price index (1995=100) .. .. .. ..

Import price index (1995=100) .. .. .. ..

Terms of trade (1995=100) .. .. .. ..

BALANCE of PAYMENTS

1983 1993 2002 2003

(US$ millions)

Exports of goods and services 6,813 16,048 37,439 41,604

Imports of goods and services 9,197 20,700 38,295 43,659

Resource balance -2,384 -4,652 -856 -2,055

Net income -859 937 4,550 1,660

Net current transfers 472 699 503 2,445

Current account balance -2,771 -3,016 4,197 2,050

Financing items (net) -725 2,850 -4,857 -1,601

Changes in net reserves 3,496 166 660 -449

Memo:

Reserves including gold (US$ millions) .. 5,922 16,180 16,115

Conversion rate (DEC, local/US$) 11.1 27.1 51.6 54.1

EXTERNAL DEBT and RESOURCE FLOWS

1983 1993 2002 2003

(US$ millions)

Total debt outstanding and disbursed 24,211 36,135 59,343 ..

IBRD 2,048 4,598 3,325 ..

IDA 61 167 208 ..

Total debt service 3,028 4,920 9,192 ..

IBRD 205 669 480 ..

IDA 1 3 7 ..

Composition of net resource flows

Official grants 83 270 178 ..

Official creditors 1,015 964 -32 ..

Private creditors 769 584 2,027 ..

Foreign direct investment 105 1,238 1,111 ..

Portfolio equity 0 0 410 ..

World Bank program

Commitments 369 428 200 ..

Disbursements 613 673 178 ..

Principal repayments 72 340 327 ..

Net flows 541 333 -149 ..

Interest payments 133 332 159 ..

Net transfers 407 1 -308 ..

Note: This table was produced from the Development Economics central database. 9/16/04

-10

-5

0

5

10

15

97 98 99 00 01 02 03

Current account balance to GDP (%)

0

10,000

20,000

30,000

40,000

97 98 99 00 01 02 03

Exports Imports

Export and import levels (US$ mill.)

0

5

10

15

98 99 00 01 02 03

GDP deflator CPI

Inflation (%)

G: 5,558

A: 3,325

D: 3,412

C: 1,686

B: 208

F: 32,790

E: 12,364

Composition of 2002 debt (US$ mill.)

A - IBRD

B - IDA

C - IMF

D - Other multilateral

E - Bilateral

F - Private

G - Short-term