indonesia associated gas survey – screening & economic...

The World Bank/GGFR Indonesia Associated Gas Survey – Screening & Economic Analysis Report (Final) 25 October 2006

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The World Bank/GGFRIndonesia Associated Gas Survey – Screening & Economic Analysis Report (Final) 25 October 2006

© PA Knowledge Limited 2006

PA Consulting Group Graha Iskandarsyah

7th Floor JI.Iskandarsyah Raya No 66C

Jakarta 12160 Tel: +62 21 2750 7500Fax: +62 21 2750 7501www.paconsulting.com

Prepared for: Prepared by:

Messrs. Bent Svensson & Franz Gerner Mike Crosetti & Dick Fuller

Version: 1.0

The World Bank/GGFR 11/1/06

FOREWORD

This Screening & Economic Analysis report is the second report under the Associated Gas Survey for Utilization of Flare Gas in Indonesia. The project is conducted under the Global Gas Flaring Reduction Partnership (GGFR), which is managed by The World Bank. The GGFR is a public-private partnership that supports national governments and the petroleum industry in their efforts to reduce flaring and venting of natural gas associated with the extraction of crude oil. In addition to the Government of Indonesia and the World Bank, current members of the partnership include BP, Chevron, ENI, ExxonMobil, Marathon, Norsk Hydro, Statoil, Shell, TOTAL, and Sonatrach, and the Governments of Angola, Cameroon, Canada, Chad, Ecuador, Equitorial Guinea, Kazakhstan, Nigeria, Norway, and the United States, as well as the OPEC Secretariat.

This report was prepared by Mike Crosetti of PA Consulting Group and Dick Fuller of Pendawa Consultama Sejati based on work carried out between December 2005 and June 2006, under the guidance of Bent Svensson and Franz Gerner of the World Bank. The authors gratefully acknowledge the support provided by the Directorate General of Oil and Gas (DirJen MIGAS), the regulatory agencies BP MIGAS and the oil companies that contributed to our case studies.

i The World Bank/GGFR 11/1/06

TABLE OF CONTENTS

Foreword i

1. Introduction 1-1 1.1 Project Background and Objectives 1-1 1.2 Organization of This Report 1-5

2. Qualitative Field Screening 2-1 2.1 Sources for Flaring Data 2-1 2.2 Updated Data on Flaring at the National Level 2-3 2.3 Qualitative Screening Results for On-shore Fields 2-5 2.4 Qualitative Screening Results for Off-shore Fields 2-11

3. Evaluation of Utilization Technologies 3-1 3.1 Output Valuation 3-2 3.2 Technology Costs 3-5 3.3 Evaluation Results 3-10

4. Quantitative Field Screening 4-1 4.1 Principal Assumptions 4-1 4.2 Evaluation Findings 4-5

5. Case Studies 5-1 5.1 Jabung 5-1 5.2 Tambun 5-4 5.3 Kaji Semoga 5-6 5.4 Conclusions 5-8

6. Next Steps 6-1

Appendices

APPENDIX A: Excerpts from Data Sources A-1

APPENDIX B: Field Maps B-2

APPENDIX C: Field Descriptions C-1

APPENDIX D: Technology Screening Model D-1

APPENDIX E: Financial & Economic Model E-1

APPENDIX F: The Clean Development Mechanism F-1

ii The World Bank/GGFR 11/1/06

1. INTRODUCTION

1.1 PROJECT BACKGROUND AND OBJECTIVES

Indonesia is the largest LNG exporter in the world, and the sixth largest gas producer. Gas reserves are currently estimated to be approximately 190 TCF. However, a number of these gas resources are currently uneconomic for development or productive utilization, such as the huge Natuna East resource as well as much of the associated gas produced along with oil.

Given the liberalization of the Indonesian gas sector under the Oil and Gas Law (Law 22/2001), increasing gas demand in both Indonesia and globally – as indicated by the dramatic increase of petroleum fuel prices, with crude oil selling earlier this year at well above $70/bbl – and reduction of subsidies for petroleum fuels in Indonesia, there are strong prospects for increased Indonesian gas development, domestic utilization and export, via both LNG and pipeline.

Currently, some 9 TCF of gas resources exist as associated gas. Exhibit 1.1 indicates the distribution of gas infrastructure and gas reserves across Indonesia.

Exhibit 1.1: Gas Infrastructure & Reserves in Indonesia

Source: 2003 MIGAS Oil & Gas Statistics and Pendawa research

Indonesia flares a significant amount of associated gas in the course of oil production. Based on 2003 data, Indonesia ranks fourth among all countries in terms of total annual gas

1-1


1. Introduction

flaring and is third highest in terms of quantities of gas flared per barrel of oil produced 1. While there was significant improvement in 2004, Indonesia still has significant potential for flaring reduction.

Flaring contributes to global warming and is a waste of economically valuable resources. In 2002, the World Bank established the Global Gas Flaring Reduction (GGFR) Partnership to support national governments and the petroleum industry for flaring reduction. Current members of this public-private partnership include:

• The World Bank

• International oil and gas producers, including BP, Chevron, ENI, ExxonMobil, Norsk Hydro, Statoil, Shell, TOTAL and Sonartrach

• National governments, including Angola, Cameroon, Canada, Chad, Ecuador, Equatorial Guinea, Indonesia, Nigeria, Norway, and the United States.

Indonesia joined the GGFR Partnership in the latter half of 2003. The GGFR objective for Indonesia is to reduce key barriers to utilization of gas that would otherwise be flared.

As part of the Indonesian country program, the GGFR conducted a workshop in Indonesia for regulatory capacity building in March, 2004. Two GGFR studies are now underway in the country. One is on the application of Clean Development Mechanism (CDM) to gas flaring reduction in the country. A number of issues are outstanding in this area, including ownership of carbon credits generated by flaring reduction projects.

The other study is a comprehensive associated gas survey and gas flaring reduction strategy, which is the subject of this report. This is the second report under the Associated Gas Survey. Both the CDM and Associated Gas studies kicked off in late August, 2005, at the Indonesian Petroleum Association annual convention. The first report of the project, the Flaring and Market Data report, was issued in December, 2005, and presented to stakeholders as part of the CDM workshop held at the World Bank Resident Mission in Jakarta.

The main purpose of the Survey is to evaluate the technical, economic, and financial viability of gas flaring reduction projects in Indonesia, and to provide recommendations for implementing these projects in the near future. The scattered and remote locations of associated gas fields in Indonesia present a unique challenge for flare gas utilization. Specifically, the project will:

• Assess the near-term market for otherwise flared gas based on technical, financial and economic considerations.

• Identify actions that can improve the commercial attractiveness of flare gas utilization

1 A Framework for Reducing Gas Flaring, Franz Gerner, World Bank, presentation given at Bandung,

Indonesia, March 15, 2004.

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1. Introduction

• Prepare a time-bound road map for the implementation of these actions through stakeholder consultation to ensure that the road map yields results.

Exhibit 1.2 depicts the four steps called for in the terms of reference. Each step is discussed in further detail below.

Exhibit 1.2: Summary of the Terms of Reference

Compile Production

Data

Identify Opportunities

Assess Potential

Projects and Barriers

Prepare Road Map

For each flaring location:• gas characteristics• production profile• proximity to infrastructure• development plans

• Identify potential uses through stakeholder consultation

• Collect technology data

• Qualitative screening• Quantitative economic &

financial analysis• Identify barriers

• Classify projects• Prepare road map to

implement projects

1. Compile Production Data. This initial step will provide an inventory of current and projected gas flaring.

2. Identify Opportunities. Based on discussions with stakeholders and review of available technologies, the second step will identify potential uses for gas that is otherwise flared.

3. Assess Potential Projects and Barriers. This step entails three discrete activities: (i) a qualitative screening of the attractiveness of opportunities identified in Step (2) above; (ii) quantitative economic and financial analysis of the projects that pass the qualitative screening; and (iii) identification of barriers to commercial attractiveness for economically viable projects. This will consider a broad range of potential barriers, including regulatory, market, institutional, technical, etc.

4. Prepare an Implementation Road Map. Taking into account the barriers identified for the economically viable projects, the final step of the study will classify the projects according to whether they are (i) economically and financially viable and commercially attractive, (ii) economically viable but not commercially attractive, or (iii) not economically viable. For categories (i) and (ii), the study will provide a detailed implementation roadmap that identifies the required steps, estimated timing and costs, responsible parties, and impacts on gas flaring and venting.

Though the study aims principally to support Indonesian government agencies and state-owned enterprises like MIGAS, BP MIGAS, BPH MIGAS, PLN and PGN, it also involves other stakeholders, particularly Producers (Production Sharing Contractors (PSCs), Technical Assistance Contractors and Pertamina) where, most likely, the investment and operational support will be required. Stakeholder ownership of the results of the study will be essential for implementation.

1-3


1. Introduction

The Study does not aim to provide definitive estimates of the total amounts of flare gas that can be economically or financially utilized for various productive applications in Indonesia. The attractiveness of any flare gas utilization option at particular flaring locations will be driven by site-specific factors such as gas composition, institutional capacity of local government, oil production profiles, etc. which can only be assessed on a site-by-site basis. Conducting such analysis for all flaring locations in Indonesia is beyond the scope of this study.

Rather, this study aims to:

• identify the conditions under which various flare gas utilization options are economically and financially attractive in Indonesia,

• provide recommendations to help make economically attractive flare gas utilization options financially attractive and institutionally feasible

• identify and assess specific project opportunities that can be developed to demonstrate the feasibility and value of flare gas utilization, leading to pilot projects that provide “proof of concept”.

The issue in Indonesia is not whether or how much gas that could be productively utilized is being flared, but rather how this gas can be productively utilized. This information is more valuable to stakeholders, and will lead to greater flare gas utilization, than a market assessment that simply identifies total quantities of flare gas that could be utilized in various ways given various assumptions.

Exhibit 1.3 presents a more detailed view of the study methodology. The study started with compilation of data on current gas flare production and possible uses of flare gas. These findings were presented in the Flaring and Market Data Report, and flaring estimates are updated in this report.

Flaring locations are then screened against qualitative criteria to identify the most promising locations for flare gas utilization projects. For these candidate fields, specific utilization technologies are then assessed to identify the most promising project opportunities. At the end of this screening process, candidate projects are classified according to and ranked within one of three categories: (i) economically and financially feasible, (ii) economically and financially feasible with intervention, and (iii) not economically feasible. The study will then present a time-bound, costed, and action-oriented road map for implementation of the most attractive projects in category (i) and recommendations as how to make projects in category (ii) financially attractive. Exhibit 1.3 also shows how these steps align with the components of the Terms of Reference shown in Exhibit 1.2. This Screening and Economic Analysis Report presents the results of Step 3. Findings from Step 4 will be presented subsequently in the Implementation Plan.

1-4


1. Introduction

Exhibit 1.3: Approach Overview

Step 4: Prepare Road Map

Step 3: Assess Potential Projects & Barriers

Step 2: Identify Opportunities

Step 1: Compile Production Data

Data Acquisition on Uses of Flare Gas

Data Acquisition on Uses of Flare Gas

List of Possible Uses

List of Possible Uses

STAKEHOLDER DISCUSSION

QUALITATIVE SCREENING

ECONOMIC & FINANCIAL ANALYSIS

IDENTIFICATION OF BARRIERS

Candidate Uses

Screened Candidates

Evaluated Candidates

Economically & Financially Feasible

Projects


Projects

Not Economically

Viable Projects

Not Economically

Viable ProjectsEconomically &

Financially Feasible with Intervention


with Intervention

Data Acquisition on

Flare Gas Production

Data Acquisition on

Flare Gas Production

Implementation Road Map

1.2 ORGANIZATION OF THIS REPORT

This report updates data on flaring in Indonesia presented in the Flaring & Market Data Report, and presents it at the field, rather than block level. It then describes the analysis conducted under Step 3, Assess Potential Projects and Barriers, and reports the principal findings of that analysis.

Ideally, utilization prospects for each flare in Indonesia would be evaluated one-by-one on a site-specific basis, assessing the costs and benefits of various utilization options against the continued flaring. However, since 47 out of 76 total production blocks in Indonesia report flaring, this approach would entail data acquisition and detailed evaluation of some 500 fields, which would be impractical.

We have therefore taken a structured screening approach in which we efficiently narrow down candidate fields to the most promising candidates for pilot utilization projects. In the final stage of the project, Step 4, Preparation of a Road Map, we will then investigate on a detailed, site-specific basis the candidates that pass this screening process with a view towards catalyzing the investment required for flare utilization in these cases. These cases can serve as examples for replication of flare gas utilization at other fields.

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1. Introduction

Our screening process begins with qualitative screening, which aims to narrow down the number of candidate fields for economic and financial analysis. The analysis distinguishes between on-shore and off-shore locations. Qualitative screening of on-shore locations sorts blocks and fields based on practical considerations such as:

• Volume of flaring by block

• Associated gas production volume by field

• Remaining associated gas reserves

• Whether associated gas production is already committed.

Flaring in off-shore locations is concentrated in fewer blocks and fields. The dynamics of PSC decision making regarding off-shore flaring differ from on-shore due to distance from markets and other infrastructure necessary for utilization. Our approach for off-shore fields is therefore to approach the PSCs with largest flaring blocks and work with them to review the economic and policy drivers that affect utilization prospects. Because of the sensitivity of this information, we will focus on GGFR members such as BP, Total and Chevron.

In parallel with the on-shore and off-shore screening, we economically evaluate the four principal utilization technologies (power generation, pipeline supply, CNG and LNG) over the range of daily flaring volumes and distances from existing pipelines and power lines encountered in Indonesia2. This technology screening enables us to identify which, if any, of the utilization technologies are superior to the others across the entire range of conditions encountered in Indonesia. Only such technologies need be considered further, since they would be the preferred choice at any particular location.

Finally, we assess in both financial and economic terms the utilization options that pass the technology screening at each of the fields that pass the qualitative screening. This quantitative screening takes account of field-specific characteristics such as volumes flared over time, and distances to existing power lines and pipelines. The quantitative screening enables us to:

• Identify those flaring locations that offer the highest financial returns for flare gas utilization. In the next stage of the project we will approach the PSCs who operate those fields to further investigate the prospects for flare gas utilization at those fields. At this later stage we may update the economic and financial analysis based on additional information that may be discovered, e.g. the actual gas composition for the field, actual needs that could be served by the flare gas at that location, etc.

2 LPG is not considered at this stage, since it is not an alternative to these options, but a technology that can be used in conjunction with these options to improve financial and economic attractiveness of flare gas utilization at a particular location. If LPG adds value, it does so with all of the primary utilization technologies, and therefore does not help distinguish between the attractiveness of the primary utilization technologies.

1-6


1. Introduction

• Assess how well the results of the economic and financial results align, as an indication of whether Government policies should be developed or modified.

• Assess the importance of CDM mechanisms in making flare gas utilization opportunities attractive.

This report presents this work as follows:

• Chapter 2 updates block-level flaring data on a national level, develops field-level estimates of flaring, and presents qualitative screening analysis and results.

• Chapter 3 presents the technology screening analysis and results.

• Chapter 4 provides the quantitative (economic and financial) analysis and results.

• Chapter 5 reviews actual flare gas utilization efforts at three fields, and draws conclusions from these case studies regarding barriers and opportunities for flare gas utilization in Indonesia.

• Chapter 6 proposes the next steps for the study.

• Appendix A describes and provides samples of principal data sources provided by Migas.

• Appendix B presents detailed block maps for each candidate on-shore block with flaring, indicating locations of fields and other infrastructure. These maps play an important role in the quantitative screening.

• Appendix C provides a brief description of each field that passes the qualitative screening. Data from these descriptions such as distances to existing power lines and pipelines are used in the quantitative screening.

• Appendix D describes the technology screening model

• Appendix E describes the field evaluation model used for the quantitative screening.

• Appendix F summarizes the Clean Development Mechanism, and how it can be used to develop additional revenue streams for flare gas utilization.

1-7


2. QUALITATIVE FIELD SCREENING

2.1 SOURCES FOR FLARING DATA

Oil and gas operations are conducted in Indonesia through the granting of Production Sharing Contracts (PSCs), Technical Assistance Contracts (TACs) and Joint Operating Bodies (JOBs). The major differences among the contracts are the productions splits, cost sharing and supervision. For ease of reference, all producers are referred to as PSCs throughout this report. The operational area covered by a particular contract is referred to as a block. A block may consist of one or more fields. Some blocks cover thousands of square kilometers and contain dozens of fields.

Consequently, opportunities for flare gas reduction must be identified and assessed at the field level. Use of field rather than block data enables more specific estimates of distance from flaring sites to potential utilization infrastructure such as existing pipelines and power generation and distribution. This allows for assessment of specific opportunities for flare gas utilization.

Though data was requested at the field level, Migas was only able to provide block level data for 2005. While this 2005 block-level data could be used to provide an overall view of gas flaring in Indonesia, older data had to be used to provide the field-level coverage for assessment of specific flare gas utilization opportunities. The sources are:

• The Indonesia Oil and Gas Statistics published each month by Migas, which

provides block-level flaring information. There are significant time lags in publication of this report. At the time of this report, the most recent month published for the Indonesia Oil and Gas Statistics is March 2005. These statistics report gross production, own-use, gas sales and flared, but only at the block rather than field level. Moreover, the methods used to define and record these volumes among the producers are not subject to any standard or specification. For example “own use” could be gas used by the operator to run production facilities, generate electricity, operate gas lifts or re-injected. Furthermore, while measurement in custody transfer situations is designed to accuracies of at least plus/minus two percent, the measurement in field operation is much less sophisticated and may be based on human estimation in some cases. Also, depending on the situation, the heating content of the gas can vary as well as the level of impurities such as water and CO2. Compounding these unknowns is the varying methodology among the various operators.

• The Annual Gas Reserves Report3 dated 2004 is used to report field-level gas reserves and gas production during 2003, but does not specify flaring. Migas compiles this report based on data received from BP Migas and the PSCs. This data includes estimated reserves in associated and non-associated fields; additions and reductions in reserves based on exploration, production experience and any other data gained during the year; and production for the year of the report. While this report provides gas production (which would include flaring) by field, it does

3 Reserve data is considered confidential by Migas and for this reason the identification of the specific

fields has been recorded by a generic identification system.

2-1


2. Qualitative Field Screening

not report flaring as a separate category. In addition, while all operators follow the same general guidelines, such as those published by the Society of Petroleum Engineers, for reserves reporting, there may be variations in interpretation from producer to producer.

• A letter provided by Migas in February 2006 providing block-level data for 2005. This data was provisional in nature, and through subsequent investigations the project team adjusted the data to more accurately reflect actual flaring4.

• The proprietary Pendawa Database, which provides spatial and infrastructure data,

and is used to assess distances to various infrastructure that might be able to utilize flare gas. This database contains the locations of the oil and gas fields, all known gas pipelines, power generation plants above 100 MW, power transmission lines 150 kv and greater, major industrial facilities that consume gas, and location of flares as shown in satellite imagery. Many isolated PLN diesel generators are also included in this database. The value of the knowledge of the location of these facilities was enhanced by the addition of topographic data to show population centers, road systems, and other logistical considerations for flare gas utilization.

Appendix A presents excerpts from the Migas data listed in the first three bullets listed above. Appendix B provides maps generated from the Pendawa database for candidate blocks identified through the screening process described below.

For national trends in flaring through 2005, this report relies on the adjusted data provided by Migas in February, 2006. To estimate field-level flaring, however, the analysis relies on the field-level production data for 2003 operations from the Annual Gas Reserves Report together with block-level flaring data for the same year from the Indonesia Oil and Gas Statistics and the Pendawa database. Since the Annual Gas Reserves Report does not break out flaring from total field-level production, our approach estimates field level flaring as follows:

1. All fields located in the candidate flaring blocks that do not show any gas production are eliminated. Field production is taken from the Annual Gas Reserves report, while block flaring is taken from the Indonesia Oil and Gas Statistics for the same year.

4 The letter updating the flaring data was received February 22, 2006, with data presented by block, except for Pertamina which was defined as a single number rather than seven entries used in the Migas Oil and Gas Statistics. The data in the letter indicated Pertamina flaring had increased over 100 MMCFD. To the team’s knowledge there hadn’t been any change from 2004 to 2005 that would have caused such an increase.

In response the team asked again in April for data by field, but that data has not been received. Migas subsequently released statistics for flaring in the 1st Quarter 2005. These statistics provide a breakdown of Pertamina flaring by block. From analysis of this data it became clear that there was an error in the Pertamina West Java data. From informal discussions with various parties, the team concludes that the flaring by Pertamina in West Java should be 30 MMCFD, not 151 MMCFD reported in the 1st Quarter 2005 data. Further, in the same discussions, the 2004 flaring for this block was revised from 16.6 MMCFD to 32 MMCFD.

An increase of 121 MMCFD of flaring in West Java would have attracted public attention. The team therefore accepts the revisions based on the informal discussions, and has adjusted the 2005 block-level data reported in the February letter accordingly.

2-2



2. The remaining fields were identified in the Pendawa database. If they were connected to an existing gas pipeline, they were eliminated.

3. It was then assumed that all remaining fields, i.e. those with at least some production but not connected to gas pipelines, were flaring and that the amount flared was equal to field production of associated gas since there is no reason a field would flare non-associated gas. Total block flaring was then confirmed not to exceed total gas production from these fields. This approach may over-estimate flaring at these fields because there is no way to identify possible own-use of this gas production from the available data.

This analysis is discussed as part of the qualitative screening in Section 1.3 below. Because field level flaring data is not available for any year, it must be inferred in the above manner from block-level flaring data, field-level production data, and existence of gas pipelines in producing fields. This approach enables identification of promising locations for flare gas utilization projects, but the underlying data not allow definitive assessment of the total amount of flaring in Indonesia that could be utilized on an economically or financially attractive basis.

This combination of data sources and approach represents the best available information for this study. Though the following three caveats exist, none threaten the fundamental validity of the analysis:

• The reporting conventions or standards defining categories of gas use (sales, own use, flared, etc.) have not been defined, and may not be uniform across operators. However, in the absence of specific evidence to the contrary, the analysis accepts this data at face value.

• The analysis relies on field-level flaring data that is nearly 3 years old. While more recent data would of course be desirable, the additional time that has elapsed between the data used and the most recent data conceivable should not compromise the validity of key findings and recommended actions. The primary importance in this screening analysis to identify the most promising locations to demonstrate flare reduction opportunities, and not to provide a definitive list of where flare gas utilization is justified or the amount of flaring that can be eliminated.

• The data has been compiled from a number of sources, so that there may be inconsistencies within the data. This is especially true with the spatial data, which compiles satellite imagery of flares, field locations, location of infrastructure such as pipelines, power lines, roads, power plants etc. For example, differences in geographic registration of satellite imagery and fields show that remotely sensed flares do not align exactly with fields. The authors of the report have reconciled data based on reasonable judgment wherever such inconsistence have emerged.

2.2 UPDATED DATA ON FLARING AT THE NATIONAL LEVEL

There are a total of 76 producing blocks in Indonesia currently, of which 47 report flaring of gas. Based on 2004 Migas Oil & Gas Statistics, the areas that report flaring represent 96% of Indonesia’s oil production and 82% of its gas production, as indicated in Exhibit 2.1.

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Exhibit 2.1: Oil & Gas Production5 2004

Total Production

Production from Flaring Blocks

Percent

Oil and Condensate (MMBOPD)

1.10 1.03 96

Gas (MMCFD) 8,302 6,827 82

This 2004 data indicates that 47 blocks containing 506 fields were flaring 358 MMCFD, as shown in Exhibit 2.2.

Exhibit 2.2: Indonesia Gas Flared 2004, Onshore and Offshore Blocks

Gas Flared Percent of Number Gas Prod Oil Prod(MMscfd) Total Flared of fields MMSCFD (BPD)

1 Petrochina Int'l Jabung Jambi/PSC/Onsh 43.4 12.1% 5 183.0 16,725.62 Pertamina-Southern Sumatra South Sumatra/Onsh 43.0 12.0% 43 258.5 14,675.73 BP West Java West Jv/PSC/Offsh 40.7 11.3% 57 351.5 30,085.44 CNOOC SES BV (Maxus) West Jv/PSC/Offsh 19.8 5.5% 34 51.4 81,684.35 Total Indonesie East Kal/PSC/Offsh 18.7 5.2% 14 2,513.5 81,984.66 Pertamina-West Java West Jv /PSC/Onsh 32.0 8.9% 34 468.2 18,905.87 Conoco Phillips - Ramba TAC South Sum/TAC/Onsh 14.5 4.0% 7 40.1 6,187.18 Medco E&P Indonesia (Rimau) South Sum/PSC/Onsh 14.2 4.0% 9 32.6 38,265.29 Star Energy - Kakap Riau/PSC/Offsh 13.0 3.6% 6 94.9 8,258.1

10 Caltex Pacific Indonesia (CPI) Riau/PSC/Onsh 10.0 2.8% 86 95.2 505,233.711 Conoco Phillips (Natuna) Riau/PSC/Offsh 8.9 2.5% 6 347.9 30,317.012 Genindo/Perkasa East Kal/TAC/Onsh 8.5 2.4% 1 9.1 5,442.213 PN-Petrochina Int'l Tuban East Java/JOB/Onsh 7.9 2.2% 1 7.8 9,334.514 Medco E&P Indonesia (SS+CS) South Sum/PSC/Onsh 7.8 2.2% 27 67.8 9,761.515 Pertamina-Northern Sumatra North Sumatra/Onsh 7.7 2.1% 19 78.6 3,701.216 Chevron Ind. Co. (Unocal Ind. Inc.) East Kal/PSC/Offsh 7.4 2.1% 14 281.1 39,041.317 Premier Oil Riau/PSC/Offsh 7.3 2.0% 1 154.0 3,079.018 PN-Petrochina Salawati Papua/JOB/Onsh 7.2 2.0% 4 7.2 3,960.619 Kodeco Energy East Jv/PSC/Offsh 4.8 1.4% 3 50.8 10,348.420 Pertamina-Central Sumatra Jambi/Onsh 4.5 1.2% 9 4.4 3,038.921 Pertamina-Irian Papua/Onsh 4.4 1.2% 1 5.0 876.022 ConocoPhillips - Grissik SouthSum/PSC/Onsh 4.0 1.1% 17 429.7 7,596.423 Kodeco Poleng East Jv/TAC/Offsh 3.6 1.0% 1 75.9 3,95324 Chevron Makasar (Unocal Makasar) South Slwsi/PSC/Offsh 2.5 0.7% 13 58.2 16,78125 Pertamina-Kalimantan East Kal/Onsh 2.5 0.7% 11 9.1 5,26426 Costa Int'l Group / Japex NS North Sum/TAC/Offsh 2.1 0.6% 1 4.9 17627 Kondur Petroleum SA Riau/PSC/Offsh 2.0 0.6% 17 6.3 9,88728 Pertamina - Talisman OK SouthSum/JOB/Onsh 1.8 0.5% 3 23.4 4,50329 Pertamina Talisman (Tanjung) Ltd South Kal/Onsh 1.8 0.5% 1 1.8 6,10230 HediI/ Citra Patenindo South Sum/JOB/Onsh 1.7 0.5% 3 8.9 1,46031 EMP-Kangean (BP-ARBNI) East Java/Offsh 1.6 0.4% 1 118.6 1,06932 Vico East Kal/PSC/Onsh 1.4 0.4% 8 900.3 28,89533 Sea Union Energy South Sum/JOB/Onsh 1.4 0.4% 5 16.0 5,41434 PT. Bina Wahana Petrindo Meruap Jambi/Onsh 1.4 0.4% 1 1.4 2,19535 GFB Resources East Jv/PSC/Offsh 1.3 0.4% 2 1.3 20636 Pilona Sidhakarya Salawati Papua/Onsh 1.0 0.3% 1 2.0 30937 Kufpec Ltd. Maluku/PSC/Onsh 0.7 0.2% 1 0.7 2,51438 Petrochina International (Bermuda) Papua/PSC/Onsh 0.7 0.2% 10 7.2 6,66739 Pertamina DOH East Java East Java/Onsh 0.38 0.1% 1 0.9 2,32640 PT. Petro Selat Riau/Onshore 0.19 0.1% 1 0.041 Medco E&P Indonesia (Tarakan) East Kalimantan/Onsh 0.15 0.0% 18 22.9 5,11342 PT. Surya Teladan South Sum/Onsh 0.14 0.0% 1 1.4 1,20943 Ranya Energi Pamanukan West Java/Onshore 0.11 0.0% 1 1.8 444 Energi Equity Epic (Sengkang) South Sulawesi/Offsh 0.05 0.0% 1 23.9 6645 Medco E&P Indonesia (Lematang) South Sum/Onsh 0.05 0.0% 1 2.1 6846 Golden Spike South Sum/Onsh 0.04 0.0% 4 3.7 30847 Haurgeulis West Java/Onsh 0.005 0.0% 1 1.7 12

Subtotal 358.3 100.0% 506 6,827.0 1,033,002Percent of 47 Blocks of Total Indonesia 82.2% 95.6%

TOTAL INDONESIA 8,301.7 1,080,042

No Company/Block Contract Area

5 Based on the 2004 Indonesia Oil & Gas Statistics from Migas .

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More recent data indicates that total flaring has decreased by 20% between 2004 and 2005, with offshore declining 27% while onshore was reduced by 16%, as shown in Exhibit 2.3.

Exhibit 2.3: Indonesian On- and Off-shore Flaring Trends6

Gas Flared Onshore and Offshore Blocks

0

50

100

150

200

250

300

1999 2000 2001 2002 2003 2004 2005

Year

MM

CFD

Offshore

Onshore

The objective of the study is to identify specific opportunities for flare gas utilization in Indonesia and develop a road map to implement them as demonstration projects that can be replicated. The identification process relies on a combination of qualitative and quantitative screens to identify the most promising locations for flare gas utilization. The criterion used at each level of screening can be adjusted to expand or reduce the number of candidate flaring sites.

While onshore flaring can draw from a wide range of recovery options, the offshore flaring is much more dependent on pipeline connections and volume thresholds. For these reasons on shore flaring and offshore flaring will be addressed separately.

2.3 QUALITATIVE SCREENING RESULTS FOR ON-SHORE FIELDS

Total onshore flaring from 33 blocks amounted to 224.5 mmscfd from 336 fields as shown by Exhibit 2.4. In comparing this data with the data for 2005, there is an apparent reduction in flaring of 37 MMCFD.

6 2005 data adjusted from the Migas letter of February, 2006.

2-5



Exhibit 2.4: Onshore Blocks Gas Flared 2004

Gas Flared Percent of Number(MMscfd) Total Flared of fields

1 Petrochina Int'l Jabung Jambi/PSC/Onsh 43.4 19.3% 52 Pertamina-Southern Sumatra South Sum/Onsh 43.0 19.2% 433 Pertamina-West Java West Jv /PSC/Onsh 32.0 14.3% 344 Conoco Phillips - Ramba TAC South Sum/TAC/Onsh 14.5 6.5% 75 Medco E&P Indonesia (Rimau) South Sum/PSC/Onsh 14.2 6.3% 96 Caltex Pacific Indonesia (CPI) Riau/PSC/Onsh 10.0 4.4% 867 Genindo/Perkasa East Kal/TAC/Onsh 8.5 3.8% 18 PN-Petrochina Int'l Tuban East Java/JOB/Onsh 7.9 3.5% 19 Medco E&P Indonesia (SS+CS) South Sum/PSC/Onsh 7.8 3.5% 27

10 Pertamina-Northern Sumatra North Sumatra/Onsh 7.7 3.4% 1911 PN-Petrochina Salawati Papua/JOB/Onsh 7.2 3.2% 412 Pertamina-Central Sumatra Jambi/Onsh 4.5 2.0% 913 Pertamina-Irian Papua/Onshore 4.4 2.0% 114 ConocoPhillips - Grissik South Sum/PSC/Onsh 4.0 1.8% 1715 Pertamina-Kalimantan East Kal/Onsh 2.5 1.1% 1116 Pertamina - Talisman OK South Sum/JOB/Onsh 1.8 0.8% 317 Pertamina Talisman (Tanjung) Ltd South Kal/Onsh 1.8 0.8% 118 Hedi/ Citra Patenindo South Sum/JOB/Onsh 1.7 0.7% 319 Vico East Kal/PSC/Onsh 1.4 0.6% 820 Sea Union Energy South Sum/JOB/Onsh 1.4 0.6% 521 PT. Bina Wahana Petrindo Meruap Jambi/Onsh 1.4 0.6% 122 Pilona Sidhakarya Salawati Papua/Onsh 1.0 0.5% 123 Kufpec Ltd. Maluku/PSC/Onsh 0.7 0.3% 124 Petrochina Int'l (Bermuda) Papua/PSC/Onsh 0.7 0.3% 1025 Pertamina DOH East Java East Java/Onsh 0.38 0.2% 126 PT. Petro Selat Riau/Onsh 0.19 0.1% 127 Medco E&P Indonesia (Tarakan) East Kalimantan/Onsh 0.15 0.1% 1828 PT. Surya Teladan South Sum/Onsh 0.14 0.1% 129 Ranya Energi Pamanukan West Java/Onsh 0.11 0.0% 130 Energi Equity Epic (Sengkang) South Sulawesi/Onsh 0.05 0.0% 131 Medco E&P Indonesia (Lematang) South Sum/Onsh 0.05 0.0% 132 Golden Spike South Sum/Onsh 0.04 0.0% 433 Haurgeulis West Java/Onsh 0.005 0.0% 1

Total 224.5 100.0% 336


The first screen eliminates onshore blocks with flaring of less than 0.7 mmscfd. Conservatively assuming a gas value of USD 10/mscf, the value of flared gas at each of these fields would be no more than approximately USD 2.5 million per year, or a present value of only USD 15 million over 10 years at a 10% discount rate. Moreover, blocks can cover thousands of square kilometers and therefore fields with flaring may be widely distributed throughout the areas. PSCs are unlikely to be highly motivated to devote the necessary resources to develop or utilize this gas, even if the actual development of the flare gas were to be carried out by another party. While these blocks might yield economically and/or financially attractive flare gas utilization opportunities, they are not the best candidates for pilot projects.

This screen reduced the number of blocks to be examined further from 33 to 24.The eliminated blocks accounted for less than 0.5% of onshore flaring as shown by Exhibit 2.5

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Exhibit 2.5: Onshore Blocks Gas Flared 2003 > 0.7 MMscfd

Gas Flared Percent of Total Number(MMscfd) Onshore Gas Flared of fields

1 Petrochina Int'l Jabung Jambi/PSC/Onsh 43.4 19.3% 52 Pertamina DOH Sumbagsel South Sum/Onsh 43.0 19.2% 433 Pertamina DOH-West Java West Jv /PSC/Onsh 32.0 14.3% 344 Conoco Phillips - Ramba TAC South Sum/TAC/Onsh 14.5 6.5% 75 Medco E&P Indonesia (Rimau) South Sum/PSC/Onsh 14.2 6.3% 96 Caltex Pacific Indonesia (CPI) Riau/PSC/Onsh 10.0 4.4% 867 Genindo/Perkasa East Kal/TAC/Onsh 8.5 3.8% 18 PN-Petrochina Int'l Tuban East Java/JOB/Onsh 7.9 3.5% 19 Medco E&P Indonesia (SS+CS) South Sum/PSC/Onsh 7.8 3.5% 2710 Pertamina DOH Sumbagut North Sumatra/Onsh 7.7 3.4% 1911 PN-Petrochina Salawati Papua/JOB/Onsh 7.2 3.2% 412 Pertamina DOH Sumbagteng Jambi/Onsh 4.5 2.0% 913 Pertamina DOH - Irian/Sorong Papua/Onsh 4.4 2.0% 114 ConocoPhillips - Grissik South Sum/PSC/Onsh 4.0 1.8% 1715 Pertamina DOH Kalimantan East Kal/Onsh 2.5 1.1% 1116 Pertamina - Talisman OK South Sum/JOB/Onsh 1.8 0.8% 317 Pertamina Talisman (Tanjung) Ltd South Kal/Onsh 1.8 0.8% 118 Hedi/ Citra Patenindo South Sum/JOB/Onsh 1.7 0.7% 319 Vico East Kal/PSC/Onsh 1.4 0.6% 820 Sea Union Energy South Sum/JOB/Onsh 1.4 0.6% 521 PT. Bina Wahana Petrindo Meruap Jambi/Onsh 1.4 0.6% 122 Pilona Sidhakarya Salawati Papua/Onsh 1.0 0.5% 123 Kufpec Ltd. Maluku/PSC/Onsh 0.7 0.3% 124 Petrochina Int'l Bermuda Papua/PSC/Onsh 0.7 0.3% 10

Total 223.4 99.5% 307


The next screen, based on analyses using the Migas Annual Reserve Report, eliminated blocks with less than 1 bcf of associated gas reserves remaining as of the end of 2003. This reduced the number of blocks from 24 to 20 and the number of fields from 336 to 126. These remaining fields still accounted for 95.7% of all onshore flaring. This is shown by Exhibit 2.6

Exhibit 2.6: Onshore Blocks Gas Flared 2004 > 0.7 MMscfd and Field Remaining Reserve > 1 BCF

Gas Flared Percent of Total Number(MMscfd) Onshore Gas Flared of fields

1 Petrochina Int'l Jabung Jambi/PSC/Onsh 43.4 19.3% 42 Pertamina DOH Sumbagsel South Sum/Onsh 43.0 19.2% 223 Pertamina DOH-West Java West Jv /PSC/Onsh 32.0 14.3% 184 Conoco Phillips - Ramba TAC South Sum/TAC/Onsh 14.5 6.5% 25 Medco E&P Indonesia (Rimau) South Sum/PSC/Onsh 14.2 6.3% 36 Caltex Pacific Indonesia (CPI) Riau/PSC/Onsh 10.0 4.4% 187 Genindo/Perkasa East Kal/TAC/Onsh 8.5 3.8% 18 PN-Petrochina Int'l Tuban East Java/JOB/Onsh 7.9 3.5% 19 Medco E&P Indonesia (SS+CS) South Sum/PSC/Onsh 7.8 3.5% 7

10 Pertamina DOH Sumbagut North Sumatra/Onsh 7.7 3.4% 1511 PN-Petrochina Salawati Papua/JOB/Onsh 7.2 3.2% 312 Pertamina DOH Sumbagteng Jambi/Onsh 4.5 2.0% 513 ConocoPhillips - Grissik South Sum/PSC/Onsh 4.0 1.8% 414 Pertamina DOH Kalimantan East Kal/Onshore 2.5 1.1% 615 Pertamina - Talisman OK South Sum/JOB/Onsh 1.8 0.8% 216 Hedi/ Citra Patenindo South Sum/JOB/Onsh 1.7 0.7% 217 Vico East Kal/PSC/Onsh 1.4 0.6% 618 Sea Union Energy South Sum/JOB/Onsh 1.4 0.6% 419 Kufpec Ltd. Maluku/PSC/Onsh 0.7 0.3% 120 Petrochina Int'l Bermuda Papua/PSC/Onsh 0.7 0.3% 2

Total 214.9 95.7% 126


2-7



Assuming a gas value of USD 10/mscf, the total value of this gas assuming it can be utilized entirely at once (i.e. without any discounting) would be USD 10 million. As with the 0.7 mmscfd criterion, this amount of gas is unlikely to greatly motivate PSCs to make the effort to development this gas. Again, while these blocks might yield economically and/or financially attractive flare gas utilization opportunities, they are not the best candidates for pilot projects.

For the third screen, all 126 fields in the 20 candidate onshore blocks were identified, and an oil field production decline rate of five percent per year was applied to the gas production rate for 2003 as given in the Annual Gas Reserve Report. Thus a production and associated gas reserves profile was created for each field to be used in determining the economics for use in each of the potential markets identified accessible from the field.

These production/reserves profiles consist of the 2003 production rate declined at five percent each year until the gas reserves are depleted. Assuming that it would be 2007 at the soonest before any flare gas utilization project could be implemented, those fields that would have less than 1 bcf remaining in 2007 due to production between 2004 - 2006 were eliminated. This screening reduced the number of fields to be evaluated to 81.

Of these 81 fields, an additional 25 fields were eliminated because they did not have any production (which includes flaring) reported in 2003 Migas Gas Reserves Report but remained on the list because their associated reserves were greater than 1 bcf. The lack of flaring in these fields suggests that other fields were the source of flaring in these blocks. It is assumed the associated gas reserves reported for these 25 fields were either being re-injected or were reserves in a gas cap and therefore not subject to flaring, thus leaving 56 fields for consideration. These fields and depletion profile for 10 years are shown by Exhibit 2.7.

The remaining 56 fields were located in the Pendawa Database, and each was individually researched. This inspection revealed that 26 fields were most likely connected to delivery pipelines and therefore it was assumed this gas was sold and not flared, i.e. the gas was already committed. Of the remaining 30 fields, those within a couple of kilometers were consolidated, as indicated in Appendix C. This left 26 flaring locations as candidates for the quantitative screening.

These 26 fields are shown by Exhibit 2.8 along with their flare gas production. These fields represent approximately 57.7 mmscfd of flaring. These fields will be quantitatively evaluated for specific flare gas utilization opportunities. Because of the confidentiality of field-level production and reserve data, we have only identified blocks by name and operator, and have coded specific fields to prevent identification of those fields

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Exhibit 2.7: Production Profile 10 yrs, those fields with reserves as at 2007

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Operator Field

1 Sea-Union A 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.4 0.42 Sea-Union B 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.13 PertaminaDOHKalimantan A 3.1 3.0 2.8 2.7 2.5 2.4 2.3 2.2 2.1 2.04 PertaminaDOHKalimantan B 0.4 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.35 PertaminaDOHKalimantan C 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.16 PertaminaDOHKalimantan D 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.17 PertaminaDOHKalimantan E 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.18 Pertamina TalismanOK A 5.6 5.3 5.0 4.8 4.5 4.3 4.1 3.9 3.7 3.59 Pertamina DOH West Java A 24.3 23.1 22.0 20.9 19.8 18.8 17.9 17.0 16.1 15.3

10 Pertamina DOH West Java B 15.6 14.8 14.1 13.4 12.7 12.1 11.5 10.9 10.4 9.811 Pertamina DOH West Java C 12.3 11.7 11.1 10.5 10.0 9.5 9.0 8.6 8.1 7.712 Pertamina DOH West Java D 7.6 7.2 6.8 6.5 6.2 5.9 5.6 5.3 5.0 4.813 Pertamina DOH West Java E 4.9 4.7 4.4 4.2 4.0 3.8 3.6 3.4 3.3 3.114 Pertamina DOH West Java F 4.2 4.0 3.8 3.6 3.5 3.3 3.1 3.0 2.8 2.715 Pertamina DOH West Java G 3.3 3.2 3.0 2.9 2.7 2.6 2.5 2.3 2.2 2.116 Pertamina DOH West Java H 2.9 2.8 2.6 2.5 2.4 2.2 2.1 2.0 1.9 1.817 Pertamina DOH West Java I 2.2 2.1 2.0 1.9 1.8 1.7 1.6 1.6 1.5 1.418 Pertamina DOH West Java J 2.2 2.1 2.0 1.9 1.8 1.7 1.6 1.6 1.5 1.419 Pertamina DOH West Java K 1.3 1.3 1.2 1.1 1.1 1.0 1.0 0.9 0.9 0.820 Pertamina DOH West Java L 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.4 0.421 Pertamina DOH West Java M 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.4 0.422 Pertamina DOH West Java N 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.123 Pertamina DOH Sumbagut A 19.5 18.5 17.6 16.7 15.9 15.1 14.3 13.6 12.9 12.324 Pertamina DOH Sumbagut B 5.2 4.9 4.7 4.4 4.2 4.0 3.8 3.6 3.4 3.325 Pertamina DOH Sumbagut C 3.4 3.2 3.0 2.9 2.7 2.6 2.5 2.3 2.2 2.126 Pertamina DOH Sumbagut D 3.9 3.7 3.5 3.3 3.2 3.0 2.9 2.7 2.6 2.527 Pertamina DOH Sumbagut E 2.5 2.4 2.3 2.2 2.0 1.9 1.8 1.8 1.7 1.628 Pertamina DOH Sumbagut F 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.129 Pertamina DOH Sumbagut G 0.9 0.9 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.630 Pertamina DOH Sumbagut H 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.6 0.6 0.531 Pertamina DOH Sumbagut I 0.7 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.432 Pertamina DOH Sum basel A 49.1 46.6 44.3 42.1 40.0 38.0 36.1 34.3 32.6 30.933 Pertamina DOH Sum basel B 11.8 11.2 10.7 10.1 9.6 9.2 8.7 8.3 7.8 7.534 Pertamina DOH Sum basel C 10.9 10.4 9.9 9.4 8.9 8.5 8.0 7.6 7.3 6.935 Pertamina DOH Sum basel D 10.5 10.0 9.5 8.5 8.1 7.7 7.3 7.0 6.636 Pertamina DOH Sum basel E 4.5 4.2 4.0 3.8 3.6 3.5 3.3 3.1 3.0 2.837 Pertamina DOH Sum basel F 4.2 4.0 3.8 3.6 3.5 3.3 3.1 3.0 2.8 2.738 Pertamina DOH Sum basel G 3.8 3.6 3.4 3.3 3.1 2.9 2.8 2.6 2.5 2.439 Pertamina DOH Sum basel H 2.5 2.3 2.2 2.1 2.0 1.9 1.8 1.7 1.6 1.540 Pertamina DOH Sum basel I 2.0 1.9 1.8 1.7 1.6 1.6 1.5 1.4 1.3 1.341 Pertamina DOH Sum basel J 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.142 Pertamina DOH Sum basel K 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.143 Medco-Rimau A 18.5 17.6 16.7 15.9 15.1 14.3 13.6 12.9 12.3 11.744 Medco-Rimau B 5.4 5.1 4.8 4.6 4.4 4.1 3.9 3.7 3.6 3.445 Kufpec A 0.9 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.6 0.646 Hedi-Haliburton A 0.9 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.6 0.647 Conoco Philips Ramba A 3.3 3.2 3.0 2.9 2.7 2.6 2.5 2.3 2.2 2.148 Conoco Philips Grissik B 3.1 3.0 2.8 2.7 2.5 2.4 2.3 2.2 2.1 2.049 Conoco Philips Grissik C 2.7 2.5 2.4 2.3 2.2 2.1 2.0 1.9 1.8 1.750 Medco CS SS A 10.9 10.4 9.9 9.4 8.9 8.5 8.0 7.6 7.3 6.951 Medco CS SS B 6.2 5.9 5.6 5.4 5.1 4.8 4.6 4.4 4.1 3.952 Medco CS SS C 3.8 3.6 3.4 3.3 3.1 2.9 2.8 2.6 2.5 2.453 Medco CS SS D 1.1 1.1 1.0 1.0 0.9 0.9 0.8 0.8 0.7 0.754 Medco CS SS E 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.155 PetroChinaBermudajabung A 24.3 23.1 22.0 20.9 19.8 18.8 17.9 17.0 16.1 15.356 PetroChinaSulawati A 0.4 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.3

Production 312.1

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

2-9



Exhibit 2.8: Remaining Candidates after committed fields deleted

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

1 Sea-Union A 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.4 0.42 Sea-Union B 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.13 PertaminaDOHKalimantan B 0.4 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.34 PertaminaDOHKalimantan C 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.15 PertaminaDOHKalimantan D 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.16 Pertamina DOH West Java G 3.3 3.2 3.0 2.9 2.7 2.6 2.5 2.3 2.2 2.17 Pertamina DOH West Java H 2.9 2.8 2.6 2.5 2.4 2.2 2.1 2.0 1.9 1.88 Pertamina DOH West Java J 2.2 2.1 2.0 1.9 1.8 1.7 1.6 1.6 1.5 1.49 Pertamina DOH West Java L 1.3 1.3 1.2 1.1 1.1 1.0 1.0 0.9 0.9 0.810 Pertamina DOH West Java M 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.4 0.411 Pertamina DOH West Java N 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.4 0.412 Pertamina DOH West Java O 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.113 Pertamina DOH Sumbagut C 3.4 3.2 3.0 2.9 2.7 2.6 2.5 2.3 2.2 2.114 Pertamina DOH Sumbagut E 2.5 2.4 2.3 2.2 2.0 1.9 1.8 1.8 1.7 1.615 Pertamina DOH Sumbagut G 0.9 0.9 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.616 Pertamina DOH Sumbagut H 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.6 0.6 0.517 Pertamina DOH Sumbagut I 0.7 0.7 0.6 0.6 0.6 0.5 0.5 0.5 0.5 0.414 Pertamina DOH Sum basel B 11.8 11.2 10.7 10.1 9.6 9.2 8.7 8.3 7.8 7.515 Pertamina DOH Sum basel F 4.2 4.0 3.8 3.6 3.5 3.3 3.1 3.0 2.8 2.716 Pertamina DOH Sum basel G 3.8 3.6 3.4 3.3 3.1 2.9 2.8 2.6 2.5 2.417 Pertamina DOH Sum basel H 2.5 2.3 2.2 2.1 2.0 1.9 1.8 1.7 1.6 1.518 Pertamina DOH Sum basel I 2.0 1.9 1.8 1.7 1.6 1.6 1.5 1.4 1.3 1.319 Pertamina DOH Sum basel J 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.120 Pertamina DOH Sum basel K 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.121 Kufpec A 0.9 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.6 0.622 Conoco Philips Ramba A 3.3 3.2 3.0 2.9 2.7 2.6 2.5 2.3 2.2 2.123 Conoco Philips Grissik C 2.7 2.5 2.4 2.3 2.2 2.1 2.0 1.9 1.8 1.724 Medco CS SS C 3.8 3.6 3.4 3.3 3.1 2.9 2.8 2.6 2.5 2.425 Medco CS SS E 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.126 PetroChinaSulawati A 0.4 0.4 0.4 0.4 0.4 0.3 0.3 0.3 0.3 0.3

Production assumed flared 57.7

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. Scfd

MM. ScfdOperator Field

Exhibit 2.9 summarizes the qualitative screens applied. These results do not mean that only 58 mmscfd of flaring might be financially and/or economically attractive for flare gas utilization. Rather, based on the data currently available, only 58 mmscfd of flaring can be reliably linked to a specific field rather than block. Field-level flaring data is essential for assessing the prospects for flare gas utilization, so these are the candidates that are subsequently subjected to quantitative screening for specific flare gas utilization opportunities.

Exhibit 2.9: Qualitative Screening Summary

2004 Blocks FieldsGas Flared

MMscfd % Blocks FieldsGas Flared

MMscfd % Blocks FieldsGas Flared

MMscfd %

Total block in Indonesia with flares 33 336 224.5 62.7% 14 170 133.8 37.3% 47 506 358.3 100%

Total Onshore blocks/fields 33 336 224.5 100%Onshore blocks flaring > 0.7 MMSCFD and onshore 24 307 223.4 99.5%Onshore fields with > 1 bcf reserves 20 126 214.9 96.2%

2007Production.

MMscfd

Fields with > 1 bcf reserves 15 81 312.1After eliminate fields with no production - gas cap/reinjection. 56 0Fields with production believed sold/utilized. 26 254.4Fields with production assumed flared. 30 57.7

TotalOnshore Offshore

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The best available indicator of the large scope for flare gas utilization in Indonesia is that in 2004 total onshore flaring from blocks with more than 1 bcf associated gas reserves and flaring of more than 0.7 mmscfd amounted to some 215 mmscfd. Though financially and economically attractive utilization of this flaring will depend on numerous site-specific factors, if all of this flaring could be utilized it could be utilized in combined-cycle power plants operating at typical Indonesian capacity factors, this gas could power some 2,200 MW, or more than one-fifth of the Government’s proposed 10,000 MW crash program.

2.4 QUALITATIVE SCREENING RESULTS FOR OFF-SHORE FIELDS

As shown in Exhibit 2.3, offshore flaring has declined substantially over the past few years. The primary reason for this reduction is the completion of a pipeline from the West Natuna area to onshore Malaysia for a gas sale. The initiation and operation of this sale allowed the use of gas, previously flared in oil production, to be incorporated into gas sales. This sale commenced in 2004 and therefore Exhibit 2.3 reflects a reduction due to a partial year of operation for 2004 and a full year of sales in 2005.

In examining the current flaring, 14 offshore blocks have been identified with a total of 134 MMCFD in flaring, see Exhibit 2.10.

Exhibit 2.10: Offshore Blocks Gas Flared - 2004

Gas Flared Percent of Number(MMscfd) Total Flared Offsh of fields

1 BP West Java West Jv/PSC/Offsh 40.7 30.4% 572 CNOOC SES BV (Maxus) West Jv/PSC/Offsh 19.8 14.8% 343 Total Indonesie East Kal/PSC/Offsh 18.7 14.0% 144 Star Energy - Kakap Riau/PSC/Offsh 13.0 9.7% 65 Conoco Phillips (Natuna) Riau/PSC/Offsh 8.9 6.7% 66 Chevron Ind. Co. (Unocal Ind. Inc.) East Kal/PSC/Offsh 7.4 5.5% 147 Premier Oil Riau/PSC/Offsh 7.3 5.5% 18 Kodeco Energy East Jv/PSC/Offsh 4.8 3.6% 39 Kodeco Poleng East Jv/TAC/Offsh 3.6 2.7% 1

10 Chevron Makasar (Unocal Makasar) South Slwsi/PSC/Offsh 2.5 1.9% 1311 Costa Int'l Group / Japex NS North Sum/TAC/Offsh 2.1 1.6% 112 Kondur Petroleum SA Riau/PSC/Offsf 2.0 1.5% 1713 EMP-Kangean (BP-ARBNI) East Java/Offsh 1.6 1.2% 114 GFB Resources East Jv/PSC/Offsh 1.3 1.0% 2

Total 133.8 100.0% 170


Two of the blocks, BP West Java and CNOOC SES (adjacent blocks in West Java), contain over 45% of all offshore flaring, and when Total’s flaring in East Kalimantan is added in, nearly 60% of offshore flaring is accounted for. Exhibit 2.11 shows this flaring in the satellite photo provided by the World Bank. (Blue indicates flaring locations in 1992, green in 1998, and red in 2004).

CNOOC initiated a gas sale in 2006 and much of this flaring has likely been eliminated. In earlier stages of the project the team visited both BP and Total specifically to discuss flaring. Both companies indicated that internal policy addressed flaring and both were in full compliance. Given that BP and Total are GGFR members and shown to have the largest reported flaring representing some 45% of total offshore flaring, the team will begin by revisiting these two PSCs to assess in further detail the amount and reasons for this flaring, and impediments to utilization.

2-11



Exhibit 2.11: Offshore Flaring in West Java

CNOOC

BP

2-12


3. EVALUATION OF UTILIZATION TECHNOLOGIES

The Flaring and Market Data Report identified five utilization technologies for consideration:

• Power generation

• Pipeline

• Compressed Natural Gas (CNG)

• Liquified Natural Gas (LNG)

• Liquified Petroleum Gas (LPG)

Since LPG typically comprises only 5 to 10% of the gas stream, it is included only in conjunction with one of the other four options to improve financial and economic attractiveness of that option.

To focus efforts on the most promising technologies, this chapter evaluates the four primary utilization technologies across the range of conditions encountered for flare gas utilization in Indonesia. If a technology is shown to be inferior for the entire range of Indonesian conditions, it will not be evaluated further for application at any specific field that has passed the qualitative screening.

The purpose of this technology screening is to compare technology options rather than justify particular projects. Consequently, consistency of assumptions across technologies is more important than the precise value used for any parameter. For example, netback values for natural gas could be calculated for a wide range of potential gas uses as a way to economically value flare gas utilization relative to continued flaring. However, the objective at this stage in the overall screening process is not to evaluate the use of a particular utilization technology at a specific location, but rather to compare utilization technologies over the entire range of plausible natural gas valuations to determine whether any of them dominate for all cases.

This analysis relies on economic analysis of the technologies at border prices with the following assumptions or conventions. Economic analysis enables evaluation of these options in terms of costs and benefits to the nation, and thereby points to options that should be encouraged from a policy standpoint. In contrast, financial analysis would include pricing and tax distortions, and does not reveal the underlying costs and benefits for the nation as a whole:

• The analysis is conducted in real terms using constant 2006 USD

• A real discount rate of 10% is applied

• There is no real escalation in costs, except for changes in the baseline energy prices used to value output.

• As this is economic analysis, duties and taxes are omitted from the analysis.

3-1


3. Evaluation of Utilization Technologies

• Greenhouse gas reduction benefits are not valued at this stage, and in any case would be nearly the same across all technologies for a given amount of flaring.

• Imported equipment and fuels are valued at CIF, and a standard conversion factor of 1 is assumed for domestic goods and services.

The analysis of each technology consists of a 10-year forecast of costs and revenues valued at economic prices for a range of flare gas volumes and other technology-specific factors, e.g. distance to existing power lines or gas pipelines. The technologies are compared on the basis of net present value of the resulting cash flows. Assumptions used in this screening are made conservatively. For example, electricity is valued at the long run marginal cost (LRMC) of gas-fired open-cycle turbines, rather than isolated diesel generators or willingness to pay. Valuing electricity at the cost of isolated diesel generation would greatly increase the value; if electricity generation is preferred to other utilization technologies when valued at the LRMC of gas-fired turbines, it would be even more strongly preferred when valued at the cost of diesel generation.

The following sections discuss the valuation of outputs used to estimate revenues resulting from application of the technology, the costs and performance of the technology, and the evaluation and comparison of the technologies over the range of Indonesian conditions.

3.1 OUTPUT VALUATION

Revenues for power generation depend upon the value of the electricity produced, whereas revenues for the other technologies depend upon the value of the natural gas made available for productive use. Each of these is discussed in turn.

3.1.1 Value of Electricity Production

There are a number of approaches that may be used to economically value electricity. For the scale of gas availability considered in this study, the amount of power produced could only be absorbed by a 20 kV grid7. Although there are isolated 20 kV systems in Indonesia, most 20 kV lines are supplied by higher voltage systems, e.g. 70 or 150 kV. Therefore, electricity is valued at the long-run marginal cost (LRMC) of generation representative of such systems.

PLN has conducted cost of service studies over the years. The most recent was completed in 2005 using 2003 data8. That study assessed cost of service on the Batam and Java-Bali systems, and as part of that analysis assessed LRMC of generation, transmission and generation.

Generation LRMC consists of energy and capacity components. The capacity component represents the cost of generating capacity to serve an additional unit of demand (power) during peak periods. The energy component represents the additional cost of fuel and

7 The minimum gas availability of 0.7 mmscfd could fire a 3 MW generator powered by a reciprocating

engine. This would be sufficient to supply some 7,500 Indonesian households in the R-1 tariff class. 8 Update of the Electricity Tariff Rationalization Study, PT PLN (Persero), March, 2005.

3-2



variable operating costs required to meet that additional unit of demand throughout the day.

The 2005 PLN study identified open-cycle gas turbines as the least-cost means of augmenting peak supply on both systems. While larger systems such as Java-Bali can accommodate larger plants, which achieve higher efficiencies and greater economies of scale, the difference in costs amounts to only about 10% to 15% less on a per kW basis than smaller systems such as Batam. (Java-Bali has peak demand of some 14,000 MW compared to a peak demand of some 120 MW on Batam.) On Java-Bali, a peaking unit would be expected to cost approximately Rp 700,000 per kW-yr, and on Batam perhaps Rp 800,000 per kW-yr. Taking the mid-point of these two cases, converting to USD at USD 1 = Rp 9,000 and assuming a system load factor of 60%, the cost of capacity is estimated to be USD 0.016/kWh.

For energy costs, peak and off-peak time-weighted average marginal energy cost was approximately USD 0.029/kWh on Java-Bali and USD 0.043 on Batam (assuming an exchange rate of USD 1= Rp 9,000). Larger systems like Sumatra would be closer to the Java-Bali figure, while smaller systems would be closer to Batam. The mid-point, USD 0.036/kWh, represents a reasonable marginal energy cost for the purposes of this analysis. However, in the PLN analysis this cost corresponds to crude oil prices of USD 25/bbl in 2004 terms. Bringing that to 2006 terms results in a base energy cost of USD 28/bbl for crude. The energy component is therefore scaled by forecast crude oil prices relative to USD 28/bbl.

3.1.2 Value of Natural Gas Production

The economic valuation methodology for natural gas depends on whether it is tradable (via LNG or an international pipeline) or non-tradable.

Tradable gas would be valued economically at its FOB price if LNG, less liquification costs, or at its price before any tax at the international transfer point if pipeline. A confidential source from on one of the largest Indonesian PSCs active in LNG cites current long-term Indonesian LNG contracts priced at some USD 9/mmBTU. Assuming the gas composition as described in Section 4.1.1 below, a liquification cost of around USD 1/mmBTU9 and rounding up to the nearest full USD, the economic value of tradable gas is estimated to be USD 10/mscf.

A standard approach for economically valuing non-tradable natural gas is to back calculate from the cost of providing the same service with a different, tradable fuel. However, this “netback” approach can be used only when a specific use has been identified for the gas. In this case, we are looking at options (pipeline, CNG and LNG) that make gas available for all consumers and all possible uses. A netback analysis is not well suited to these circumstances, as there are a plethora of uses and corresponding alternative tradable fuels that may be envisioned.

9 This estimate is consistent with numerous sources including the International Energy Agency, the US

Energy Information Administration, Oil & Gas Bulletin: Liquified Natural Gas, RW Beck Inc., 2006, and “LNG Cost Reductions and Flexibility in LNG Trade Add to Security of Gas Supply”, Sylvie Cornot-Gandolphe, Energy Prices & Taxes, 1st Quarter 2005.

3-3



If we were to assume the one of the highest value non-tradable uses, electricity production, and prepare a netback analysis, we would arrive at roughly the same value as the tradable valuation. Referring to Section 3.1.1, the electricity energy marginal cost is USD 0.036/kWh at an oil price of USD 28/bbl. Updating this to an oil price of USD 70/bbl suggests an energy marginal cost of USD 0.090/kWh. Assuming the gas composition described in Section 4.1.1 and an open cycle efficiency of 38%, we arrive a netback value of about USD 11.50/mscf.

However, despite the liberalization of fuel prices in Indonesia late last year, and the ability of producers and consumers to negotiate prices directly in a relatively less regulated environment, the same confidential source from one of the largest Indonesian PSCs notes that some domestic gas contracts are now priced at USD 5/mmBTU at the wellhead, though many negotiated prior to the run-up in world oil prices are priced less. This pricing is consistent with the observation that a large portion of domestic gas is not used for high-value activities like electricity production. (Only about 40% of total domestic gas consumption is for electricity. The dominant domestic use is for petrochemical and fertilizer feedstock). Using the gas composition defined in Section 4.1.1 and rounding up to the nearest USD, the corresponding gas value is USD 6/mscf. To give an indication of this relative to international benchmarks, this is consistent with the Henry Hub spot price at the time of USD 70/bbl oil.

0.00

0.50

1.00

1.50

2.00

2.50

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004

Year

Pric

e In

dex

Crude Oil

Natural Gas(wellhead)

To project the economic value of gas over time, we have indexed the gas price to crude oil prices. In liberalized markets such as the United States, these prices are well correlated reflecting their function as substitutes. Exhibit 3.1 shows the relationship of US wellhead gas prices with crude oil prices, with the price of each indexed to 1.0 in 1986, after gas sector liberalization was underway. In the late 1980s the gas market was still in the process of development, but by the 1990s the market had evolved to the point where gas prices largely tracked crude prices with a lag of up to 1 year.

Exhibit 3.1: Relationship between Crude Oil & Natural Gas Prices in the US10

10 Energy Information Administration website, 2006.

3-4



Therefore, the two cases for economic valuation of natural gas corresponding to USD 70/bbl crude oil are USD 6/mscf and USD 11/mscf. The latter reflects both the high-value domestic netback as well as the tradable case. The analysis assumes that these gas valuations will track the crude oil price forecast. The forecast assumed in this analysis is provided in Exhibit 3.2. This forecast reflects a cyclic view of crude oil prices following a long-term upward trend, as suggested by historical data shown in Exhibit 3.3.

Exhibit 3.2: MOPS Brent Crude Oil Price Forecast

0

1020

3040

5060

7080

90

2006 2008 2010 2012 2014 2016

Year

Con

stan

t 200

6 U

SD p

er b

bl

Exhibit 3.3: World Crude Oil Prices, 1947-2004

3.2 TECHNOLOGY COSTS

Technology costs were derived from a number of industry sources. In several cases, actual installed costs from various projects were taken as data points to confirm an expected

3-5



relationship between, for example, the volume of gas processed and capital cost of a particular type of equipment.

The analysis incorporates the cost of the following technologies. For this analysis, the gas was assumed to be sweet, so no sweetening was required:

Gensets Reciprocating gas engines are assumed. This is the technology choice throughout Indonesia for small, gas-powered electricity generation. Numerous vendors are active, including Deutz, Catepillar, GJenbacher, etc. Installed capitcosts (duty excluded) as a function of capacity are given in the chart to the right. Specific fuel consumption is assumed to be 8.83 scf/kWh (0.25 Nm3/kWh), and annual O&M cost is assumed to be 5% of capital costs.

E al

y = 907.4x-0.2419

0

200

400

600

800

1,000

1,200

0 5 10 15 20

MW

Cos

t per

MW

, 200

6 '0

00 U

SD

Power lines 20 kV lines are assumed. PLN typically budgets between USD 8,000 and 35,000 per km depending on location and required capacity. USD 20,000 km is assumed here.

Compression (to 30 bar)

Compression is required to bring associated gas that has been separated from the crude stream to pressure suitable for pipeline transport or other processing such as CNG or LNG. The cost for cis shown in the figure to the right.

ompression

Dehydration Dehydration is required to remove moisture from the gas stream to meet transmission pipeline specifications and input requirements for LPG, CNG, and LNG processing. The installed cost for dehydration is shown in the figure to the right.

y = 0.3559x + 0.0371

0.000.501.001.502.002.503.003.504.00

0 2 4 6 8 10

MMSCFD

Inst

alle

d C

ost,

2006

mill

ion

USD

y = 1.0395x0.6

0.000.501.001.502.002.503.003.504.004.50

0 2 4 6 8 10

MMSCFD

Inst

alle

d C

ost,

2006

mill

ion

USD

3-6



Chilling Chilling entails use of a compression cooling system to remove condensates from the gas stream to meet transmission pipeline specifications and input requirements for LPG, CNG, and LNG processing. The installed cost for chilling is shown in the figure to the right.

y = 0.2962x + 0.74

0.00

1.00

2.00

3.00

4.00

0 5

MMSCFD

Inst

alle

d C

ost,

2006

m

illio

n U

SD

10

ost g

ortation

nd he

tal costs for

gas

Pipeline 6 inch pipe is assumed for all cases at a cost of USD 120,000 per km. For the pipeline option, annual O&M costs are assumed to be 5% of total capital costs (including costs of compressors, dehydration, etc.)

Entry metering & controls

Entry end metering and pressure & flow control is assumed to cost USD 50,000/mmscfd.

Receiving facilities

Receiving facilities at the discharge end of the pipeline for transfer of custody into a transmission pipeline are assumed to cost USD 50,000/mmscfd.

CNG Compression

CNG pressurizes gas to approximately 3,000 psi. This requires additional compression. The energy consumption of this compression is assumed to be 1.6% of the gas stream, and the annual O&M cost is assumed to 5% of the total capital costs (i.e. including cost of dehydration, compressors, chilling, etc.). The cost of CNG compression is assumed to be USD 397,500 per mmscfd.

CNG Storage The CIF cost for CNG storage tanks is assumed to be USD 1,125 per mscf. It is assumed that 1 day storage is required at the production site, and 3 days storage at the consumers site.

CNG Transportation

CNG transportation capital cincludes the cost of loadinstations and trucks. Because of the greater volumes required for transporting the same amount of energy in the form of LNG, CNG transpcosts are much expensive per mmscf-km than LNG. The number of trucks required depends on the distance aamounts transported. Tfigure at the right shows CNGtransportation capivarious average delivery distances, as a function ofvolume.

0.00

2.00

4.00

6.00

8.00

10.00

12.00

0 2 4 6 8 10

MMSCFD

Cos

t, 20

06 m

illio

n U

SD

50 km 100 km 150 km

3-7



LNG Liquification

A number of small-scale LNG liquification technologies are now available and being used commercially around the world. It is assumed that 20% of the gas stream is used to run the process. Annual O&M costs are assumed to be 5% of total capital costs. The figure at the right shows the costs for LNG liquification.

LNG Storage LNG storage costs are less than CNG per mmscf of gas due to the greater density of the fuel. The figure at the right indicates LNG storage cost as a function of gas volume.

LNG Transportation

As noted above, LNG transportation capital costs are also less than for CNG. . The figure at the right shows LNG transportation capital costs for various average delivery distances, as a function of gas volume.

LNG Regasification

Once delivered, LNG must be converted from liquid back to gas. The figure at the right shows LNG regas costs as a function of gas volume. This cost includes the cost of 2 days storage at the delivery site.

y = 2.9114x0.8561

0

5

10

15

20

25

0 2 4 6 8 1

MMSCFD

Inst

alle

d C

ost,

2006

mill

ion

USD

0

y = -0.0024x2 + 0.1406x + 0.0569

0.000.20

0.400.600.801.00

1.201.40

0 2 4 6 8 10

MMSCFIn

stal

led

Cos

t, 20

06 m

illio

n U

SD

0.00

0.50

1.00

1.50

2.00

2.50

0 2 4 6 8 10

MMSCFD

Cos

t, 20

06 m

illio

n U

SD

50 km 100 km 150 km

y = 0.2209x + 0.4811

0.00

0.50

1.00

1.50

2.00

2.50

3.00

0 2 4 6 8 10

MMSCFD

Inst

alle

d C

ost,

2006

mill

ion

USD

Exhibit 3.4 summarizes the sources of cost data that went into developing these cost relationships, and Exhibit 3.5 summarizes which cost components are assumed for each technology.

3-8



Exhibit 3.4: Sources for Cost Data ITEM SOURCE

Gensets G.E. Energy Indonesia / GE Jenbacher Power lines PT. Perusahaan Listrik Negara (PLN). (Indonesia Electricity Authority.) Compressors to 30 bar Ingersol Rand. P.C Mckenzie Co. Pittsburgh. Pa. USA. Compressors to 250 bar IMW Industries Ltd., Chilliwack, BC, Canada

Knox Western, Erie, PA, USA Dehydration equipment Air Products USA.

Natural Gas Dehydration, F.Binci, F.E. Ciarapica, Giacchetta, et al. Dept. of Energetics, Faculty of Engineering, University of Ancona, Italy

Chilling (condensates removal)

Pendawa own sources. Costs based on recent project installations Indonesia.

Pipeline Indonesian pipeline industry generalized costing recent projects- US$20,000/inch-km for open areas.

Energy metering & controls

Pendawa own sources. Costs based on recent project installations Indonesia

Receiving facilities - discharge end of pipeline

Pendawa own sources. Costs based on recent project installations Indonesia

CNG storage CP Industries, McKeesport, PA, USA CNG transportation Pendawa own model Indonesian input costs. Incorporates, Capex, travel

speeds/distances, labor, fuels O&M, insurance LNG liquification Cryotech Co. Ltd., Pathumthani, Thailand.

Kryopak Inc., New Braunfels, TX USA Avidan, Richardson, Anderson, Woodard. "LNG Plant scale-up could cut costs further" Petroleum Economist 2001 “Small-scale LNG facility development” B.C Price Black & Veatch Prichard Inc. Hydrocarbon Processing, January 2003

LNG transportation Pendawa own model using Indonesian input costs based on Chart Applied Technologies, Burnsville MN USA

LNG storage Cryotech Co. Ltd., Pathumthani, Thailand. “Small-scale LNG facility development” B.C Price Black & Veatch Prichard Inc. Hydrocarbon Processing, January 2003

LNG regasification Cryotech Co. Ltd., Pathumthani, Thailand. Kryopak Inc., New Braunfels, TX USA

Exhibit 3.5: Components Used for Each Technology

Component Power Gen Pipeline CNG LNG Gensets Power lines Compression (to 30 bar) Dehydration Chilling Pipeline Entry metering & controls Receiving facilities CNG Compression CNG Storage CNG Transportation LNG Liquification LNG Storage LNG Transportation LNG Regasification

3-9



3-10


3.3 EVALUATION RESULTS

The model used to compare technologies is provided in Appendix D. Additional notes on the assumptions going into the analysis are noted there.

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0 2 4 6 8 10

Flare Gas Availability, mmscfd

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0 2 4 6 8 10

Flare Gas Availability,

Exhibit 3.6 shows the screening results for a gas value of USD 6/mscf, and Exhibit 3.7 shows the results for USD 11/mscf. For the various cases, the distances indicated are the assumed distances to existing power lines, pipelines or average delivery distances for the power generation, pipeline and CNG/LNG options respectively. (Please note that the NPV of power generation at a distance of 3 km from existing distribution lines is virtually the same as at a distance of 30 km).

Exhibit 3.6: Economic Comparison of Utilization Technologies, Gas @ USD 6/mscf

Net

esen

t 2

US

Pr

Val

ue,

006

mill

ion

D

Power Gen (3 km)Power Gen (30 km)Pipeline (3 km)Pipeline (30 km)CNG (20 km)CNG (150 km)LNG (20 km)LNG (150 km)

mmscfd

Net

Pre

sent

Val

ue, 2

006

mill

ion

USD

Power Gen (3 km) Power Gen (30 km)

Pipeline (3 km)Pipeline (30 km)

CNG (20 km)CNG (150 km) LNG (20 km)

LNG (150 km)

Exhibit 3.5: Economic Comparison of Utilization Technologies, Gas @ USD 11/mscf


This analysis suggests the following:

• For the lower gas valuation, power generation dominates the other technologies across the entire range of distances and gas volumes. The cost difference between distances for the power generation option is insignificant, which is why electricity is typically generated on the production site and transmitted by power lines, rather than laying pipeline to locate power generation closer to load centers.

• For the higher gas valuation, pipeline and power generation dominate CNG and LNG across the entire range of distances and gas volumes. The order of ranking for pipeline and power generation depends upon the distances involved.

• Only at the higher gas valuation does CNG compete with LNG. The greater storage and transportation costs for CNG limit its competitiveness.

These findings are consistent with expectations. CNG is generally limited to specialty use as a transport fuel. For the range of distances considered here, LNG will never compete with pipelines. And whether pipelines or power generation are preferred depends upon the distances involved and the value of gas.

3-11


4. QUANTITATIVE FIELD SCREENING

This chapter describes the quantitative screening, which entails the financial and economic analysis of selected utilization technologies at the flaring locations that passed the qualitative screening. It is assumed that utilization options are constructed during 2007, and begin operation at the start of 2008. Only the first 9 years of operation are considered in the analysis. To put this in context, the discounted present value of any cost or benefit occurring in year 10 is only about one-third its value if it occurred today.

Appendix E presents the model financial and economic model used for the analysis. Given that pipeline and power generation options economically dominated CNG and LNG over the entire range of expected distances and gas volumes, the following four utilization options are considered:

• Pipelines

• Pipelines in conjunction with LPG extraction

• Power generation

• Power generation in conjunction with LPG extraction.

4.1 PRINCIPAL ASSUMPTIONS

4.1.1 Gas Composition

Gas composition varies field to field. However, to conduct this quantitative screening, we assumed a baseline gas composition to facilitate assessment of requirements for gas sweetening, production of LPG, and potential carbon reduction. Exhibit 4.1 shows our assumed baseline gas composition for different levels of C3+C4. Our base case is for 5% C3+C4 at the wellhead, with processed (lean) gas at 0% C3+C4. We assume further than H2S is negligible.

For fields that pass this quantitative screening, we will seek gas composition data for the individual fields as part of our approach to the PSCs as part of preparation of the road map.

4.1.2 Financial and Economic Values

All of the values for economic costs, outputs, crude oil price forecasts, and economic discount rates used for the technology screening are used here as well. In addition the following financial values are used:

• Discount rates. The 10% real economic discount rate used in the technology screening is applied again here for the economic analysis. For the financial analysis, an 8% real financial discount rate is used. This corresponds to the weighted average cost of capital (WACC) calculated for PLN in 2005 as part of its most recent cost of service study. Power generation is one of the two principal utilization technologies, so comparison with PLN is reasonable. For the other technology, pipelines, many of the characteristics of that business are similar to PLN’s transmission business.

4-1


4. Quantitative Field Screening

Exhibit 4.1: Baseline Gas Composition 0% C3+C4

Treated Gas, Mole

%

Component HHV, Btu/ft3

HV, Btu/ft3

H2S Hydrogen Sulfide 0.00 0 0.0 C3 47.7 mmbtu/mtCO2 Carbon Dioxide 2.80 0 0.0 C4 46.9 mmbtu/mtN2 Nitrogen 2.00 0 0.0 Mix 47.3 mmbtu/mtCH4 Methane 87.00 1010 878.7C2H6 Ethane 8.50 1769.6 150.4C3H8 Propane 0.00 2516.1 0.0C4H10 I-Butane 0.00 3251.9 0.0C4H10 N-Butane 0.15 3262.3 4.8C5H12 I-Pentane 0.02 4000.9 0.7C5H12 N-Pentane 0.01 4008.9 0.4C6H14 Hexanes 0 4755.9 0.1C7H16 Heptanes + 0 5502.5 0.0C8H18 n- Octane 0 6248.9 0.0C9Hn 0 6260 0.0C10H8 Napthalene 0 5854 0.0

100% 1,035 0 mt of LPG/mscf of gas

5% C3+C4Treated

Gas, Mole %


HV Btu/ft3

H2S 0 0 0.0CO2 2.65 0 0.0N2 1.89 0 0.0

CH4 Methane 82.26 1010 830.8C2H6 Ethane 8.04 1769.6 142.2C3H8 Propane 2.50 2516.1 62.9C4H10 I-Butane 2.50 3251.9 81.3C4H10 N-Butane 0.14 3262.3 4.6C5H12 I-Pentane 0.02 4000.9 0.7C5H12 N-Pentane 0.01 4008.9 0.4C6H14 Hexanes 0.00 4755.9 0.1C7H16 Heptanes + 0 5502.5 0.0C8H18 n- Octane 0 6248.9 0.0C9Hn 0 6260 0.0C10H8 Napthalene 0 5854 0.0

100% 1,123 3.05 mt of LPG/mscf of gas

10% C3+C4Treated

Gas, Mole %


HV Btu/ft3

H2S 0 0 0CO2 2.52 0 0N2 1.80 0 0

CH4 Methane 78.30 1010 790.83C2H6 Ethane 7.65 1769.6 135.3744C3H8 Propane 5.00 2516.1 125.805C4H10 I-Butane 5.00 3251.9 162.595C4H10 N-Butane 0.13 3262.3 4.3453836C5H12 I-Pentane 0.02 4000.9 0.6589482C5H12 N-Pentane 0.01 4008.9 0.368017C6H14 Hexanes 0.00 4755.9 0.1284093C7H16 Heptanes + 0 5502.5 0C8H18 n- Octane 0 6248.9 0C9Hn 0 6260 0C10H8 Napthalene 0 5854 0


15% C3+C4Treated

Gas, Mole %


HV Btu/ft3

H2S 0 0 0.0CO2 2.38 0 0.0N2 1.70 0 0.0

CH4 Methane 73.95 1010 746.9C2H6 Ethane 7.23 1769.6 127.9C3H8 Propane 7.50 2516.1 188.7C4H10 I-Butane 7.50 3251.9 243.9C4H10 N-Butane 0.13 3262.3 4.1C5H12 I-Pentane 0.02 4000.9 0.6C5H12 N-Pentane 0.01 4008.9 0.3C6H14 Hexanes 0.00 4755.9 0.1C7H16 Heptanes + 0 5502.5 0.0C8H18 n- Octane 0 6248.9 0.0C9Hn 0 6260 0.0C10H8 Napthalene 0 5854 0.0


Components

Components

Components

Calorific Value, C3+C4

Components

4-2



• Electricity prices. For the technology screening, the economic value of electricity was set to the LRMC for energy and generation capacity as calculated in PLN’s 2005 cost of service study. The energy component was indexed to the crude oil price, so that changes in fuel prices affect the economic value of electricity, as expected. The financial price of bulk electricity sold by power generation owner is set at 60% of LRMC, which results in a bulk tariff of USD 0.064/kWh at current fuel prices. This is slightly below PLN’s prevailing average tariff yield of approximately USD 0.066/kWh. Indexing bulk tariffs to fuel costs is consistent with the four-part power purchase agreements used in Indonesia for large independent power producers, which treat fuel as a cost pass-through. In addition, for smaller plants the Government is setting bulk tariffs as percentage of PLN cost of service. For example, under Ministry of Energy and Mineral Resources Ministerial Decree No. 2/2006, the bulk power price from renewable generators up to 10 MW delivered at 20 kV is set at 80% of the “cost of service”, which is not defined in the Decree.

• Gas prices. The technology screening utilized a range of economic values for gas based on the historical relationship between gas and petroleum prices in liberalized markets. For the financial analysis, two prices are used. For flare gas that a power plant owner must purchase to run its generator, the price is set at 30% of the pipeline sale price. This low value reflects the fact that the gas would otherwise been flared, and would not have generated any value for the PSC. The pipeline sale price is set at USD 3.00/mmBTU in constant terms over the life of the project. Though this is less than the USD 5/mmBTU cited in Section 3.1.2 for the economic valuation, it better reflects the general conditions in the market and is a reasonable assessment of what a developer could expect to receive for most projects, as opposed to the best projects at the margin. There is a great deal of uncertainty about the future trajectory of domestic gas prices in Indonesia given that many issues around the implementation of the Domestic Market Obligation have not yet been resolved and major gas transmission systems are still under development. Indonesian LNG is earning significantly higher prices, but the bulk of the domestic market has been stuck in this low range despite high global energy prices.

• LPG prices. LPG prices have a reasonable correlation with crude oil prices. We have used the relationship between crude and LPG prices over the past 36 months to set LPG prices. At the crude oil prices of USD 70/bbl, and including margins for insurance and freight, the corresponding LPG price is USD 627/mt CIF. CIF values are used for the economic valuation of LPG. Financial prices for the sale of bulk LPG from the extraction facility is set at 80% of economic value, in view of there is little or no existing LPG bottling or transportation infrastructure near the extraction sites.

y = 0.9592x0.5989

0.000.501.001.502.002.503.003.504.00

0 2 4 6 8 1

MMSCFD

Inst

alle

d C

ost,

2006

mill

ion

USD• LPG capital costs. The cost of the

LPG extraction plant is given in the figure to the right as a function of gas throughput. This is the installed cost excluding duties. The LPG extraction plant is assumed to require dehydration and chilling units, the costs of which are accounted for separately.

0

4-3



• Development costs. In addition to capital and operating costs, any flare gas utilization project will entail costs for design, permitting, contract preparation and negotiation. These are assumed to be independent of the size of the project. Development costs are give as USD 500,000 for pipeline or power generation projects, and USD 750,000 for these projects when LPG extraction is added. These costs exclude preparation of projects under the Clean Development Mechanism, described in the following section.

• Other capital costs. All other capital costs are the same as the capital costs used in the technology screening analysis. However, a 10% import duty has been applied to convert these figures to financial values. Value-added tax (VAT) is omitted from the financial analysis, since the actual financial impact of valued-added tax is limited to the difference between VAT output and input, which can only be determined at a consolidated level for the taxable entity.

4.1.3 Environmental Benefits

Flare gas utilization can reduce or eliminate visual blight and noise pollution, as well as local air pollution due to heavy metal, SOx and NOx emissions from the flare. There are no financial benefits associated with these environmental consequences, and any economic benefit would be highly site specific and of speculative value in the absence of detailed studies. Consequently, these benefits are not valued in the analysis.

In contrast, flare gas utilization generates global environmental benefits for project sponsors through the Clean Development Mechanism (CDM). Appendix F describes CDM and how it creates a market for the reduction of greenhouse gases (GHG) such as CO2 produced as a result of flaring.

The GHG reduction (measured in tons equivalent of CO2, t CO2 eq) that can be attributed to a particular intervention depends upon the comparison of t CO2 eq emissions at the project boundary with and without the project. For example, if the utilization of flare gas for power generation or pipeline supply results in consumption that would not have otherwise occurred in the absence of the project, then there is no GHG reduction benefit. If on the other hand, electricity generation or pipeline supply displace combustion of the same fuels that would have occurred in the absence of the project, then the reduction is the amount of GHG emissions that would have been produced by the displaced combustion.

We assume this latter case. Both pipeline gas and electricity supply are increasing rapidly in Indonesia. Flare gas utilization projects are assumed here to displace combustion of the same fossil fuels from other source that that would have otherwise taken place. Therefore, the amount of GHG reduction resulting from these projects is equal to the t CO2 eq attributable to the flare, less any losses on site, e.g. use of gas to power compressors. Based on analysis of the baseline gas composition at 5% C3+C4, this represents 62.7 t CO2 eq per mmscf of gas.

As discussed in Appendix F, recent CDM transactions have been in the range of € 6 to 16/t CO2 eq for the categories of projects corresponding to gas flaring reduction. Taking a somewhat conservative approach based on recent transactions, a range of USD 0 to 15/t CO2 eq is assumed here, with a base case of USD 7.50/t CO2 eq. The same range is used for the economic analysis. For sensitivity cases in which CDM revenues are generated, the financial and economic models extend these revenues beyond 2012 though there is no

4-4



guarantee this market will continue past that date. However, given discounting, the impact of this is relatively small. In any case, this serves as an upper bound, with no carbon value as the lower bound.

4.2 EVALUATION FINDINGS

The results of the economic and financial analysis are shown in Exhibit 4.2 for two cases of carbon valuations, USD 0/t CO2 eq and USD 15/t CO2 eq. The charts order the fields by decreasing economic or financial net present value (NPV). The fields are identified by the corresponding numerical codes, which are used to preserve confidentiality. These exhibits report for each field the maximum value from among the four flare gas utilization options considered (power generation alone, power generation with LPG extraction, pipeline supply, and pipeline supply with LPG extraction).

Exhibit 4.2: Quantitative Screening Results

Economic Valuation, USD 0/t CO2 eq

14

15 162413 6 22 7 23 17 8 189 2110 1 11 3 26202519 12 2

020406080

100120140160180200

Field

NPV

, 200

6 m

illio

n U

SD

Economic Valuation, USD 15/t CO2 eq

14

1524 16 6 2213 7 2317 8 189 21 10 1 11 3 2620 19 25 2 12

0204060

80100120140

160180200

Field

NPV

, 200

6 m

illio

n U

SD

Financial Valuation, USD 0/t CO2 eq

14

15 16 24 13 6 22 7 23 17 8 189 21 10 1 11 3 26 20 19 25 2 12

0

20

40

60

80

100

The results of the analysis indicate that:

• There is no significant discrepancy between the fields selected under the economic analysis and those selected under the financial analysis. Moreover, the overall valuation of each project and the ordering of projects are consistent between economic and financial analyses. While there may be other reasons to adjust gas pricing policies in Indonesia, doing so is not likely to affect the prospects for flare gas utilization.

120

Field

NPV

, 200

6 m

illio

n U

SD

Financial Valuation, USD 15/t CO2 eq

14

15 16 24 6 13 22 7 23 17 8 189 21 10 1 11 3 26 20 19 25 2 12

0

20

40

60

80

100

120

Field

NPV

, 200

6 m

illio

n U

SD

4-5



• Though the use of CDM adds value for project sponsors, but does not significantly change the ranking of projects or make marginal projects highly attractive attractive.

• Some projects are obviously far more attractive than others. Applying an NPV threshold of USD 30 million for the economic threshold and USD 15 million for the financial valuation leaves 10 fields that should be considered further, representing flaring of approximately 42 mmscfd. An NPV of USD 15 million is a reasonable estimate of the lower end of valuations that will motivate PSCs or other parties to seek to utilize these flares. Exhibit 4.3 identifies these 10 fields by operator/block, estimated amount of flaring in 2007, financial NPV of the project at USD 0 and 15/t CO2 eq, and the flare gas utilization option providing maximum value.

• These 10 candidates are operated by three PSCs: Pertamina, Medco and ConocoPhillips, with Pertamina representing about three-quarters of these opportunities.

• Power generation appears to dominate other utilization options, but confirmation requires site specific review and discussions with PSCs.

These 10 fields will be the focus of the next stage of the project.

Exhibit 4.3: Target Fields for Flaring Reduction

Field FieldNo Code14 Pertamina DOH Sum basel B 11.8 16.7 95.4 102.2 Power Generation15 Pertamina DOH Sum basel F 4.2 42.1 29.9 33.6 Power Generation16 Pertamina DOH Sum basel G 3.8 4.2 28.2 30.0 Power Generation24 Medco CS SS C 3.8 8.6 26.5 29.5 Power Generation13 Pertamina DOH Sumbagut C 3.4 6.3 23.5 26.0 Power Generation6 Pertamina DOH West Java G 3.3 15.2 23.1 26.0 Power Generation

22 Conoco Philips Ramba A 3.3 24.4 22.8 25.7 Power Generation7 Pertamina DOH West Java H 2.9 12.5 19.3 21.8 Power Generation

23 Conoco Philips Grissik C 2.7 54.6 17.9 20.2 Power Generation17 Pertamina DOH Sum basel H 2.5 37.1 15.3 17.5 Power Generation

Financial NPV, USD 15/tCO2eq

Technology UsedOperator & Block MMSCFD in 2007

Remaining Reserves, bcf

Financial NPV, USD 0/tCO2eq

4-6


5. CASE STUDIES

The quantitative screening suggests that opportunities to utilize flare gas can yield significant benefits to PSCs and/or project developers. Nonetheless, many opportunities apparently go undeveloped.

This chapter summarizes three case studies of successful efforts to utilize flare gas at three fields in Sumatra and Java. The purpose of these case studies is to help identify success factors for implementation. These case studies were developed through interviews with PSC personnel, local government officials, and developers involved in the projects.

5.1 JABUNG

The PetroChina Jabung PSC is located in Jambi Province (central Sumatra). The development of the PSC was based on gas field gas developed for delivery to Singapore via pipeline, as shown in Exhibit 5.1. The green areas are oil fields, and the red and pink areas are gas fields.

The gas from the fields of the Jabung PSC is rich in LPG and therefore a LPG extraction plant was included in the development. First gas flowed to Singapore from this area in 2003.

As gas is sold to Singapore at a very attractive price of 115% of the equivalent fuel oil in Singapore, currently approximately $11 to 12/MMBTU, the incentive is strong to develop gas resources in the PSC for delivery to Singapore.

However, the Ripah Field (seven oil wells) represents a modest oil discovery with some associated gas. While located only some 5-6 km from the main processing facilities, the modest amount of gas production, < 5 MMCFD, and the low pressure made capture of the gas a low priority project for PetroChina.

The power project value is US$6.5 million and comprises three gas engine-driven generating units, 2 x 2.7 MW and 1 x 2.3 MW, and a gas collection filtering and metering system close to the well-heads. A 20kV transmission system, costing Rp 17 billion paid by the local government, sends power to a distribution system for residential and industrial consumers.

Four main parties are involved, PetroChina, an exploration and production company as the supplier of the gas, Tanjung Jabung Power (TJP) as the main generating company, the local government as co-investor and PLN as electricity buyer and distribution system operator.

It is unclear if this development scenario evolved principally because of the efforts of TJP and local government, or was simply based on the economics of low volume low pressure – probably both. What is known is the local government approached PetroChina concerning support for the development of the communities in the Jabung PSC area.

Recent forms of the production sharing contract include a provision for Domestic Market Obligation (DMO) for natural gas. DMO is a concept that is derived from the oil sector. DMO for oil has long been a feature of the PSC based on assuring supply for domestic

5-1


5. Case Studies

petroleum needs. With the development of the domestic gas market, this concept has found its way into the PSC for gas also.

The Jabung PSC was established prior to the institution of DMO for gas. However, the existence of the concept and the concern for social responsibility combined to influence PetroChina to support the local government’s desire for community development.

The Jabung PSC occupies an area of the coastal plain in central Sumatra that is sparsely populated due to the marshy conditions and with the corresponding difficulty in supporting agricultural activities. The nearest PLN distribution system is over 50 km from the Kuala Tungkal area.

From the study team’s interview, it appears that the project was actually initiated by the regional PLN management. The electrification ratio is only 40% for the area and apparently PLN saw the opportunity to expand service the regional population center of Kuala Tungkal, some 40 km to the north of the field flaring gas.

Another key element of the project is the developer, Mr. Bambang Sutedjo. Mr. Sutedjo has an extensive background in local government relations and community development through his participation in Indonesia’s transmigration program11.

So, the unique combination of an area without electricity supply, a supporting local government, support from PLN and a knowledgeable developer overcame the reticence of the PSC operator and a project materialized.

In the project, the gas is purchased at the flare site, transported 1.1 km by pipeline and used in gas engines (2x2.7 MW and 1x2.3 MW) to produce electricity. The electricity is sold to PLN and transmitted via a 40 km 20 kV transmission line for use at Kuala Tungkal.

The developer purchased, installed and operates the gas pipeline and the generating facilities. To “fast track” the development most of the $6.5 million cost needed to be equity as the supporting supply and sales agreements were not finalized prior to equipment purchase. The local government owns a small (unspecified) portion of this project.

The local government also formed a BUMD (regional government-owned company) and entered into agreement with PLN for the transmission line. The Rp 17 billion needed for the line and associated facilities was borne by the local government.

The project required a gas sales agreement (GSA) and a power purchase agreement (PPA).

The GSA is for the period until 2017, the expiration of PetroChina’s control on the PSC. There is a renegotiation every five years for volumes. The price was not given but it is probably in the $2.00 to 3.00/MMBTU range, a substantial discount to the price received for gas sold in Singapore and the source of reluctance on behalf of PetroChina to supply the gas.

11 The transmigration program is an effort by the central government to relocate persons from the densely

populated areas of Java to other areas of Indonesia, thus solving the drain on Java’s resources while expanding development in Indonesia. The incentive is the provision for the ownership of plots of land in the transmigration areas, complete with supporting community services.

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5. Case Studies

The PPA was negotiated with the regional PLN office and approved by the headquarters. It provides an 80% capacity factor with different electricity sales prices above and below the capacity factor. The PPA is revisited every year. (PPAs longer than one-year in duration must be approved by the PLN Board of Directors in Jakarta, rather than the local PLN business unit).

The main project drivers were prior corporate experience of the TJP management and strong desire by local government to increase electricity penetration above the pre-project level of 40%. TJP’s management’s previous activities involved land clearing for transmigration that required close working involvement with local government. The combination of these drivers paved the way for rapid progress and relatively expedited approvals for requirements such as licenses and permits.

The project was initiated in early 2003 and was completed in August 2006. TJP felt that the development effort was relatively routine. Only the requirement for the use of equity capital was a burden.

The system will have a peak load of 5.5 MW and an average load of 2.5 MW. TJP plans to expand the capacity to 20 MW.

At the time of the conceptualization of the project the methodology for establishing CDM was not clear. For this reason, no baseline was established and the CDM process was initiated. TJP plans to incorporate a CDM application in any expansion of the operation.

Exhibit 5.1: The Jabung Field

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5. Case Studies

5.2 TAMBUN

The Tambun Field, located in West Java Province approximately 40 km west of Jakarta, was discovered by Pertamina in 2002 and went into production in 2003 at 4,000 barrels per day. The oil produced from the field is transported to the Balongan refinery by tank trucks. At the time of start up, the gas flared was between 6 and 7 mmscfd.

By 2004 production of oil was up to the current value of 8,000 barrels per day and the gas flared varies between 12 and 15 mmscfd. The gas is rich containing some 13% propane and 6% butane, plus some hexanes.

Pertamina agreed to sell the raw gas to the Bekasi Regency (BR). Pertamina and the BR have signed a 10 year contract with deliveries beginning in late 2005 for 12 MMCFD for the first five years and for 10 MMCFD for the second five years. The sales price of the raw gas is $1.85/MMBTU.

In trying to understand the Pertamina decision to sell the gas to the BR a number of factors influenced the decision. First the relative value of the revenue streams needs to be considered. At the time of the decision, 8,000 BPD of oil production would generate about $160,000/day ($20/BBL). The gas revenues would be less than $30,000.

In addition to the financial consideration, Pertamina required certain support from BR for operations in the area such as road right-of-way (ROW) and operating permits. In fact, the Tambun Field faced substantial resistance upon the commencement of operations as the single flare installed radiated too much heat, killing nearby crops, and caused noise pollution.

Demonstrations and road blockages at the site began and operations were impaired. As a solution, a second flare was installed, and operations proceeded. Another factor in the sale of the gas to BR by Pertamina was, during this period, because of the new Oil and Gas Law (Law 22/2001), Pertamina was in transition to become a state-owned limited-liability company (persero). During this period, there wasn’t a clear methodology for Pertamina to undertake commercial arrangements and dealing with a government owned entity probably looked like the lowest risk solution.

From the rich gas, the BR recovers condensate and gas. The BR is cooperating with a private company to construct a LPG recovery plant, which is expected to be operational by 2007. A pipeline connecting the Tambun Field to the Pertamina pipeline system was constructed and was completed in late 2005. The gas is being sold to Cikarang Listindo, Pupuk Kujang and other unspecified customers. The sales price wasn’t specified.

BR also constructed the pipeline in partnership with a private company. To undertake this endeavor the BR has formed a BUMD (a regional government-owned company) PT Dina Bangun Wibawa Mukti. The BR cited the experience of the Banten Regency, which has formed a distribution company12, as a model for development in BR.

12 Pendawa has previously met the officals from the Banten Province distribution company. Their

activities are based on 10 MMCFD of supply purchased directly from Pertamina. Our discussions were in Nov 2004 and Pendawa doe not know their current plans but have “heard” the Banten Regency is having supply problems with Pertamina.

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5. Case Studies

Exhibit 5.2: The Tambun Field

The rich gas leaves the wellhead at ~ 50 psig and three compressors have been installed to raise the processed gas pressure to ~ 400 psig for entry into the Pertamina pipeline at Tegal Gede. One compressor will be for standby.

The pipeline company installed the pipeline on land owned by BR, i.e., alongside the rivers, irrigation canals and ditches owned by BR, thereby avoiding any ROW matters that could arise.

The BR clearly had ambitious plans for an expanding their gas business. BR indicated that future Pertamina gas supply in the area was dedicated to BR and BR would be attempting to expand their distribution business. BR also made it clear that this business has no relationship to the regional government’s right to share in revenues from oil and gas production under Law 25/2001.

In examining the barriers to the capture of this flare gas the first problem encounter is ROW and land title13. Next was the problem of finding the commercial form for conducting this development by Pertamina.

Another significant problem was within BR itself. The financial decentralization law, Law 25/2001, was new and the procedures for the regencies to conduct business were not clear.

13 Land title, as previously mentioned, is subject to Adat law which adds substantial confusion and delays.

The World Bank has published an excellent report, More Than Just Ownership, 2004, World Bank, which helps understand the difficulties associated with adat law.

5-5


5. Case Studies

The formation and use of a BUMN company at the regency level is a relatively new approach14.

In addition, the BR experienced a change of leadership during the project development period apparently including not only the changing of personnel but also the controlling political party.

Another problem was the first private sector developer selected to assist BR wasn’t able to provide the capital needed. The determination and resolution of this problem required time.

Most of these barriers appear to be from dealing with events for the first time and subsequent flaring situations, in this area, should be resolved in a more expedient manner.

5.3 KAJI SEMOGA

The Rimau block is located approximately 100 km northwest of Palembang in South Sumatra. This block was originally awarded to Exxon and Mobil, each with a 50% stake in the venture, in 1973. In 1995, Medco took over the block from Exxon and Mobil. Medco developed the Kaji and Semoga fields in starting in 1997.

Production at these fields ramped up so that by 2000, Medco was flaring approximately 40 mmscfd of gas from the two fields combined. (Since 2003, Medco has implemented a “no flare” policy.) A number of operational uses were identified for this associated gas. In addition, the gas from these fields is rich, containing roughly 12% C3+C4. Consequently, Medco submitted an amendment to its Plan of Development (POD) in 2000 to allow recovery of costs for associated gas utilization per the terms of its PSC. BP Migas approved the POD amendment in 2002, and the project was completed in 2004.

The project entails a gas gathering system linking the Kaji and Semoga fields to utilize the 60 mmscfd of associated gas now produced. This gas is utilized for the following purposes, in descending order of priority:

• 7 mmscfd consumed by power generation for field needs

• 45 mmscfd is used for gas lift and pressure maintenance, and re-injected

• 4 mmscfd provided to the open cycle gas turbine at Talang Duku, which sells power to PLN.

• 4 mmscfd extracted as LPG at the Kaji LPG Extraction Plant

Exhibit 5.3 shows the configuration of the associated gas gathering and utilization system.

14 As a result of Law 25/2001 the regional governments formed an association, APEKSI (Asosiasi

Pemerintah Kota Selurah Indonesia - Association of Regional Governments), to study problems, exchange information and find solutions for the regional governments.

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5. Case Studies

Exhibit 5.3: The Kaji-Semoga Associated Gas Utilization System

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5. Case Studies

Approximately 4 years passed from the submission of the POD amendment proposal until the new associated gas utilization system was operational. As a result, a large amount of gas was flared during this period.

Much of this delay was likely attributable to the transition taking place as a result of Law 22/2001, e.g. the establishment of BP Migas. While processing and approval times have no doubt improved since then, PSCs would of course like even faster processing. Doing so could help reduce the total amount of gas flared by more quickly enabling PSCs to implement flare utilization projects. Moreover, BP Migas does not require disclosure of forecast flaring or proposed systems for utilization of associated gas as part of a POD submission. More generally, there are no regulations clearly governing disposition of flare gas in PSC operations.

5.4 CONCLUSIONS

These case studies suggest the following critical success factors for flare gas utilization projects:

• The recognition by the PSC or a separate project developer of the financial gain that can result from the project, and the view that this gain is worth the effort.

• The involvement and support of local government (principally at the level of the kabupaten) greatly facilitates permitting and provision of ROW that may be required for any particular project. In most cases, given the localized nature of flare gas utilization benefits (e.g. helping satisfy local electricity needs), local government has more to gain from the implementation of flare gas utilization projects than the central government, and effectively has the authority to determine whether these projects proceed.

• For power projects in particular:

o Committed local developers who understand how to work with local government and local communities are necessary, as small-scale power generation projects may be viewed as a distraction by foreign PSCs.

o The involvement and support of the PLN regional business unit for the purchase of power is of course necessary to make the project remunerative for the developer.

These case studies also suggest the following actions would help improve flare gas utilization:

• The POD process should explicitly require estimates of any expected gas flaring, and discussion of options considered to utilize that gas.

• POD amendments to utilize flare gas should be prioritized and processed on a “fast track” basis.

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5. Case Studies

• The capacity of local governments to understand the commercial aspects of these projects, and engage other parties such as PSCs and developers on this basis, should be strengthened.

• Further articulation of a framework for small-scale power generation, detailing aspects such as approval of PPAs and bulk pricing for these projects, would facilitate investment in such projects.

• Government guarantees of some sort, at either the local or national level, would help mitigate a principal source of risk for investors. The central government is currently developing such a framework, while local governments would need considerable help in doing so.

• The scale of projects envisioned is inadequate to attract the interest of foreign banks. On the other hand, domestic banks are unfamiliar with the risks of these sorts of projects, and project finance more generally. Further work with domestic banks to assess their willingness and ability to finance such projects is warranted.

Finally, a point not explicitly brought out in the case studies concerns the risk aversion of government and state-owned companies during the dynamic and uncertain environment that has prevailed in Indonesia since 1998.

In particular, the reform of the oil and gas sector appears to have had one of the largest direct effects on flaring. One of the primary goals of this sector reform was the transformation of Pertamina from its role of commercial enterprise, sector regulator and social services provider to a traditional commercial role as a PSC.

During this transition period, which is not yet completed, the flaring from Pertamina operated areas has more than doubled. One of the primary reasons is the lack of a clear, acceptable and approved contracting procedure for Pertamina activities. The fear of activities being labeled “irregularities” by state auditors in an unclear environment with changing procedures has overridden the possible benefits of accepting commercial risk. Pertamina has subsequently developed “cooperation agreements” for this purpose, but the effectiveness of these agreements is not yet apparent.

5-9


6. NEXT STEPS

This report will be distributed to various stakeholders, including PSCs, relevant Government agencies, and potential developers, along with an invitation to attend a workshop to discuss the report. It is anticipated the workshop will be held in early December.

Based on the findings of this report, the following actions are proposed by the study team for the final stage of the project following the July workshop:

• Contact Pertamina, ConocoPhillips, and Medco to discuss the specific on-shore flare reduction opportunities identified in this report. Explore the prospects for integrating these efforts with World Bank-financed projects for rural electrification in the Musi Banyu Asin (MUBA) district of South Sumatra.

• Contact BP and Total to discuss specific off-shore flare gas reduction opportunities identified in this report.

• Contact PLN and the Directorate General of Electricity and Energy Utilization to discuss in further detail mechanisms to facilitate use of flare gas for small-scale power generation.

• Work with BP Migas (based on the official request of Migas) on measures to promote flare gas utilization as part of the POD process.

• Based on the above activities, prepare a Road Map for implementation of flare gas utilization projects. It is anticipated the Road Map would be submitted in January, 2007, and would be followed by the final workshop.

To facilitate discussion of the specific flare gas utilization opportunities identified in this report, it would be helpful for The World Bank/GGFR program to formally seek approval from Migas to identify the names of the 10 target fields.

6-1


APPENDIX A: EXCERPTS FROM DATA SOURCES

This appendix provides excerpts from each of the three data sources from Migas to facilitate understanding of the data reconciliation approach used for this analysis.

The basic document to determine flared gas data is that reported in the Indonesia Oil and Gas Statistics published by the Directorate General of Oil and Gas (Migas). This publication is issued in monthly, quarterly and annual from.

Migas receives this data from BP Migas. After receipt of the data, Migas processes and publishes the information. This is a lengthy process and therefore the data available isn’t “current”. For example, the latest data available le at this time is from the first quarter of 2005.

The specific data of interest is contained in Table 3.4 Production and Utilization of Natural Gas of the document. The flaring estimate comes from the column labeled “Losses/Flared”. See Attachment One for this table from the 2004 annual edition.

The second source document used to identify flaring situations was the Indonesia Gas Reserves Data 2004. This data represents the information from January 1, 2004 and is the latest data available.

This data also comes from BP Migas via the operators. The data represents Initial Gas in Place, Maximum Recoverable Gas, 2003 Production, Cumulative Production and Remaining Reserves. This is confidential data that cannot be released without the permission of the Government of Indonesia. Consequently, Attachment Two shows the format of the data reported for each field, but has omitted the field names and values to preserve this confidentiality.

The final document available was Migas’ four page response letter of February 22, 2006, provided as Attachment Three. Subsequent investigation indicates that flaring in the Pertamina areas, reported here only in total, was substantially over-stated. The team adjusted these figures for use in the report based on informal discussions with relevant parties.

A-1


Appendix AAttachment OnePage 1 of 2

Appendix AAttachment OnePage 2 of 2

Appendix AAttachment TwoPage 1 of 2

PROVEN, PRODUCING FIELD BCF

ASS NON ASS ASS NON ASS ASS NON ASSPERTAMINA

1. DOH -NAD-SUMBAGUTAST-PANG. SUSU

1 ARUBAY2 BESITANG3 GEBANG4 P.TABUHAN BARAT5 P. TABUHAN TIMUR6 PANTAI PAKAM TMR7 POLONIA8 PULAU PANJANG9 SECURAI

10 TUNGKAM11 WAMPU

2. DOH -NAD-SUMBAGUTAST. RANTAU

1 KUALA DALAM2 KUALA SIMPANG BRT3 KUALA SIMPANG TMR4 PEMATANG PANJANG5 PERAPEN6 RANTAU7 SERANG JAYA8 SUNGAI BULUH

3.DOH SUMBAGTENGJAMBI

1 BUNGIN BATU2 KETALING BRT3 KETALING TMR4 SENGETI5 SETITI TENGGARA6 SUNGAI GELAM C7 SUNGAI LILIN8 TUBA OBI

4.DOH SUMBAGTENGLIRIK

1 MOLEK

5. DOH SUMBAGSELASS PRB BRT/PDP

1 BENAKAT TIMUR2 BENUANG3 BERNAI4 BETUN5 BETUN SOUTH-EAST6 BETUNG7 BULU8 CANDI9 DERAS

10 IBUL SOUTH-EAST11 JIRAK12 KAYA SOUTH-EAST13 KRUH NORTH14 LOYAK15 MUSI16 RAYU17 SELO18 SOPA19 SUKARAJA20 T.AKAR/PENDOPO21 TALANG GULA

COMPANY/FIELDNO

SUB TOTAL DOH SUMBAGSELASSPRB BRT / PDP

REMAINING

NATURAL GAS RESERVE BY FIELDJANUARY 1, 2004

INITIAL GAS IN PLACE MAXIMUM RECOVERY PRODUCTION 2003

PRODUCTION CUMULATIVE

SUB TOTAL DOH-NAD-SUMBAGUTAST PANG.SUSU

SUB TOTAL DOH-NAD-SUMBAGUTAST RANTAU

TOTAL DOH-NAD-SUMBAGUT

SUB TOTAL DOH SUMBAGTENGJAMBI

SUB TOTAL DOH SUMBAGTENGLIRIK

TOTAL DOH SUMBAGTENG

Appendix AAttachment ThreePage 1 of 4

B: Field Maps

APPENDIX B: FIELD MAPS

This appendix presents the maps of each block containing fields that have passed the qualitative screening.

B-2


APPENDIX C: FIELD DESCRIPTIONS

To maintain commercial confidentiality field names have been coded. The information is presented as: Operator Field Type of Opportunity and details. Medco CS SS.

C Power Generation Option: yes Why: Gas reserves. PLN 20kV distribution line within 20km. Flat open terrain Major city population within 35 km

Possible barriers: Power this region mostly from main grid and large power stations. Commonly adequate power supply. Bureaucratic. Gas quality Commercial Gas may already be committed Small Scale LNG Option: no Why: other options superior No known markets in the region

CNG. Option: no Why: other options superior No known markets in the region

Pipeline Option: yes Why: Gas reserves.

Possibility to connect to Gunung Kembang field 13 km away. That is already connected to Pertamina pipeline,

Flat open terrain

Possible barriers: Available capacity in Gunung Kembang pipeline unknown. Bureaucratic. Gas quality Commercial Gas may already be committed Pipeline entry pressure,

C-1


C: Field Descriptions

LPG

Option: yes Why: Gas reserves. Pipeline option will require gas treatment to pipeline specification..

Possible barriers: 20km to nearest main road. Bureaucratic. Gas quality Commercial Gas may already be committed Medco CS SS.

D Power Generation Option: No Why: Gas reserves.

Small Scale LNG Option: no Gas reserves.

CNG. Option: no Gas reserves.

Pipeline Option:no Gas reserves.

LPG Option:No Gas reserves. Medco CS SS.

E Power Generation Option: yes Why: Gas reserves > 10 yrs. PLN 20kV distribution line within 3km. Flat open terrain Major city Sekayu, within 15 km Possible barriers: Power this region mostly from main grid and large power stations. Commonly adequate power supply. Bureaucratic. Gas quality

C-2



Commercial Gas may already be committed

Small Scale LNG Option: no Why: other options superior No known markets in the region


Pipeline Option: No Why: Small daily production 0.2 MMscfd Closest connection point to Pertamina pipeline > 30km. Swamp and open ground

LPG Option: No Why: No need to treat gas for power generation No pipeline option Conoco Philips Ramba

A Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 15km. Flat jungle/open terrain one large river crossing. City Grissik, large population within 50 km Possible barriers: . Power this region mostly from main grid and large power stations. Commonly adequate power supply Bureaucratic. Gas quality Commercial Gas may already be committed..


CNG. Option: no

C-3



Why: other options superior No known markets in the region

Pipeline Option: yes Why: Gas reserves > 10yrs. Pertamina pipeline within 8km Flat jungle/open terrain one large river crossing. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed.. Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Gas reserves > 10yrs. Pipeline option will require gas treatment to P/L spec. Pertamina products terminal within region Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed.. Major road min 20km away Conoco Philips Grissik.

C Power Generation

Option: yes Why: Daily production 2.7 MMscfd, Reserves > 10 yrs. PLN 20kV distribution line within 3 km. Flat open terrain. City Rimborahat, within 7 km Possible barriers: Gas may already be connected to Pertamina pipeline. Power this region mostly from main grid and large power stations. Commonly adequate power supply Bureaucratic. Gas quality Commercial

C-4





Pipeline Option: yes Why: Pertamina pipeline within 5 km Daily production 2.7 MMscfd, Reserves > 10 yrs. Flat open terrain. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Daily production 2.7 MMscfd, Reserves > 10 yrs. Pipeline option will require gas treatment to P/L spec. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Major road < 3 km away. Pertamina Sumbagut C Power Generation Option: yes Why: Daily production 3.4MMscfd PLN 20kV distribution line within 10 km. City Pangalansusu, within 10 km Possible barriers: Reserves. Water and swampy terrain 7 km. Power this region mostly from main grid and large power stations. Commonly adequate power supply Bureaucratic.

C-5



Gas quality Commercial Gas may already be committed.


CNG. Option: no Why: other options superior No known markets in the region Pipeline Option: yes Why: Daily production 3.4MMscfd Pertamina pipeline within 15 km Water and Swamp terrain 5 km flat open terrain 10 km. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Pipeline option will require gas treatment to pipeline specification. Pertamina products terminal/refinery within 20km Possible barriers: Water and swampy terrain 7 km. Reserves. Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina Sumbagut I Pertamina Sumbagut E Pertamina Sumbagut H . Pertamina Sumbagut G Join these 4 fields together by pipeline. Combined 4.9 MMscfd. Reserves adequate. Pipeline and power options

C-6



Power Generation Option: yes Why: Combined daily production 4.9 MMscfd PLN 20kV distribution line within 10 km. Town Pulaukumpai, within 10 km Possible barriers: Swampy terrain 7 km. Power this region mostly from main grid and large power stations. Commonly adequate power supply Bureaucratic. Gas quality Commercial Gas may already be committed. LNG Option: no Why: other options superior No known markets in the region CNG. Option: no Why: other options superior No known markets in the region Pipeline Option: yes Why: 4.9MMscfd

Pertamina pipeline within 12 km. Field connection pipelines 10km total.

Water and Swamp terrain 5 km flat open terrain 10 km. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown. LPG Option: yes Why: Pipeline option will require gas treatment to P/L spec. Pertamina products terminal/refinery within 20km Possible barriers: Water and swampy terrain 7 km. Reserves. Bureaucratic. Gas quality

C-7



Comercial Gas may already be committed. Pertamina West Java

H connect with J

Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 20km. Flat open terrain . City Majalengka, within 15 km New power plant could source gas from 2 fields. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why: Gas reserves > 10yrs. Pertamina pipeline within 40km Flat open terrain. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why:

C-8



Gas reserves > 10yrs. Pipeline option will require gas treatment to pipeline specification. Within 12km of main road Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina West Java

G Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 1km. Flat open terrain . City Indramayu, within 15 km Recent discovery. Appraisal 2005. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why: Gas reserves > 10yrs.

Pertamina pipeline within 10 km to known block valve. (Entry pont).

Flat open terrain. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pipeline entry pressure not known.

C-9



LPG

Option: yes Why: Gas reserves > 10yrs. Pipeline option will require gas treatment to P/L spec. Pertamina products terminal/refinery within 40 km by main road. Field within 1km of main road. Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina West Java

L connect with

N Power Generation

Option: yes Why: Reserves > 10+yr. PLN 20kV distribution line within 15km. Flat open terrain . Closest city Rangasdengklok, 20km small rd. 20km to main rd.

Small daily production 1.3 and 0.7, MMscfd respectively but may be possible to increase.

Possible barriers: Bureaucratic. Gas quality Commercial Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: No Why: More than 50 km to nearest Pertamina pipeline. Power option superior Additional other possible barriers:

C-10



Bureaucratic. Gas quality Commercial Gas may already be committed. Pipeline entry pressure not known. Built up region.

LPG Option: yes Why: Reserves, may be possible to increase MMscfd rate. Possible barriers: Distance to Pertamina fuel depot not known. 20 km of small road to main road. May limit transport load. Requires LPG separation plant Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina West Java

M. Power Generation Option: yes Why: Gas > 10+yr reserves PLN 20kV distribution line within 1km. Flat open terrain. City Indramayu, within 40 km Possible barriers: Bureaucratic. Gas quality Low daily production (0.7MMscfd). Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why: Gas reserves > 10yrs.

C-11



Pertamina pipeline within 10km Flat open terrain. Possible barriers: Low daily production (0.7MMscfd). Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Gas reserves > 10yrs. Pipeline option will require gas treatment to pipeline specification. Within 1 km of main road Possible barriers: Low daily production (0.7MMscfd). Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina West Java

O Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 5km. Flat open terrain . City Purwakarta, within 50 km Possible barriers: Low daily production (0.2MMscfd). Bureaucratic. Gas quality Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



C-12



Pipeline Option: yes Why: Gas reserves > 10yrs. Pertamina pipeline within 10km Flat open terrain. Possible barriers: Low daily production (0.2MMscfd). Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Gas reserves > 10yrs. Pipeline option will require gas treatment to pipeline specification. Pertamina products terminal/refinery within 100km Within 3km of main road Possible barriers: Low daily production (0.2MMscfd). Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina DOH Kalimantan.

B Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 5km. Closest city Sangata, within 5 km Diesel generation on extension from Bontang Possible barriers: Low daily production 0.4MMscfd.. Hilly terrain Bureaucratic. Gas quality Gas may already be committed.


C-13



CNG.

Option: no Why: other options superior No known markets in the region

Pipeline Option:No Why: No pipeline access in area.

LPG Option: no Why: Small daily production Pertamina DOH Kalimantan.

C Connect by 19 km gas pipeline to

D Power Generation Option: yes Why: Combined fields gas reserves > 10yrs. PLN 20kV distribution line within 15km. Closest city Tanjung, within 15 km. Possible barriers:

Low daily production 0.2MMscfd each field combined 0.4MMscfd.. Hilly terrain Bureaucratic. Gas quality Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why:

Joined together combined daily production 0.4 MMscfd. Reserves > 10 yrs.

C-14



Distance D to C 19 km, from C, South to to Pertamina pipeline 17 km, Possible barriers: Low daily production. Bureaucratic. Gas quality - may need treatment to pipeline spec. Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown. Hilly terrain

LPG Option: no Why: Small split daily production Remote location. Kufpec A Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 8km. Closest city Buka, within 16 km Currently diesel generation < 1MW. Small local stand alone system Gas production 0.9 MMscfd adequate for 5-6MW Possible barriers: Continuity of supply - associated gas. Hilly terrain Bureaucratic. Gas quality Equipment transportation, everything by ship.



Pipeline Option: No Why: No pipeline access in area.

C-15



LPG

Option: no Why: Small daily production Remote location. Long distance to formed roads. Sea Union A Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 5km. Flat open terrain . City Prambumulih, within 13km Medium level daily production (0.7MMscfd). Possible barriers: Bureaucratic. Gas quality Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why: Gas reserves > 10yrs. Pertamina pipeline within 10km Flat open terrain. Reserves. Possible barriers: Daily production (0.7MMscfd). Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Gas may already be committed. Pipeline entry pressure, Pipeline block valve location as entry point unknown. LPG

C-16



Option: yes Why: Gas reserves > 10+yr. Pipeline option will require gas treatment to pipeline specification.. Within 5km of main road Possible barriers: Low daily production (.7MMscfd). Bureaucratic. Gas quality Commercial Gas may already be committed. Sea Union B Power Generation Option: yes Why: Gas reserves > 10yrs. PLN 20kV distribution line within 5km. Flat open terrain . City Prambumulih, within 20km Possible barriers: Low level daily production (0.2MMscfd). Bureaucratic. Gas quality Gas may already be committed. Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why: Gas reserves > 10yrs. Pertamina pipeline within 5km Flat open terrain. Possible barriers: Daily production (0.2MMscfd). Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Gas may already be committed.

C-17



Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG

Option: yes Why: Gas reserves > 10yrs. Pipeline option will require gas treatment to pipeline specification. Within 5km of main road Possible barriers: Low daily production (0.2MMscfd). Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina DOH Sumbasel E

No options proposed Reserves finish 2007. To Pertamina pipeline 2km most likely already connected. Pertamina DOH Sumbasel B Power Generation Option: yes Why: Gas high daily production rate 11.8 MMscfd. PLN 20kV distribution line within 5km. Flat open terrain . City Prambumulih, within 60 km Possible barriers: May already be connected to pipeline Reserves. Bureaucratic. Gas quality Power this region from major grid large power plant Reliable supply already.



C-18



Pipeline Option: yes Why: High daily production 11.8 MMscfd Pertamina pipeline within 5km Flat open terrain. Possible barriers: May already be connected to pipeline Reserves. Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: High daily production 11.8 MMscfd Pipeline option will require gas treatment to pipeline specification. Within 5km of main road Possible barriers: Reserve. Bureaucratic. Gas quality Commercial Gas may already be committed. Pertamina DOH Sumbagsel F Power Generation Option: yes Why: Gas daily production rate 4.2 MMscfd

Gas reserves > 10 yrs. PLN 20kV distribution line within 7km. Flat open terrain . City Pendopo, within 7 km Possible barriers: May already be connected to pipeline Bureaucratic. Gas quality Power this region from major grid large power plant Reliable supply already.


C-19



CNG. Option: no Why: other options superior No known markets in the region Pipeline Option: yes Why: Pertamina pipeline within 5km Gas daily production rate 4.2 MMscfd.

Gas reserves > 10 yrs. Flat open terrain. Possible barriers: May already be connected to pipeline Bureaucratic. Gas quality - may need treatment to pipline spec. Commercial Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Gas daily production rate 4.2 MMscfd.

Gas reserves > 10 yrs. Pipeline option will require gas treatment to pipeline specification. Within 5km of main road Possible barriers: Gas may already be committed. Bureaucratic. Gas quality Commercial Pertamina DOH Sumbagsel

G Daily production 3.8 Mscfd, Gas reserves > 10 yrs.

Pertamina DOH Sumbagsel K Daily production 0.2 Mscfd,

Gas reserves < 10 yrs.

Proposal: Connect the fields G and K together by 7km pipeline.

Power Generation Option: yes Why: G within 1 km of PLN 20 kV system. Combined Production 4.0 MMscfd. Flat open terrain . City Pendopo, within 7 km Possible barriers: May already be connected to pipeline

C-20



Bureaucratic. Gas quality Power this region from major grid large power plant Reliable supply already.



Pipeline Option: yes Why: Pertamina pipeline within 5km field F. Combined Production 4.0 MMscfd. Flat open terrain. Possible barriers: May already be connected to pipeline Bureaucratic. Gas quality - may need treatment to pipeline spec. Commercial Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Pipeline option will require gas treatment to Pipeline specification.. Within 5km of main road Possible barriers: Gas may already be committed. Low daily production.

Reserves Bureaucratic. Gas quality Commercial Pertamina DOH Sumbasel H Power Generation Option:No Why: Nearest Power line connection point > 50km

Small Scale LNG

C-21



Option: no Why: other options superior No known markets in the region


Pipeline Option: yes Why: Pertamina pipeline within 13km Gas daily production rate 2.5 MMscfd.

Gas reserves > 10 yrs. Flat open terrain. Possible barriers: May already be connected to pipeline Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Pipeline option will require gas treatment to pipeline specification. Gas daily production rate 2.5 MMscfd.

Gas reserves > 10 yrs. Possible barriers: Nearest main road >30 km Gas may already be committed. Bureaucratic. Gas quality Commercial Pertamina DOH Sumbagsel I Power Generation Option: yes Why: PLN 20kV distribution line within 3 km. Gas daily production rate 2.0 MMscfd. Flat open terrain . City Pajaraman, within10 km Possible barriers: Reserves. Bureaucratic. Gas quality

C-22



Power this region from major grid large power plant Reliable supply already.



Pipeline Option: No Why: Nearest Pertamina pipeline >30 km away.

LPG Option: No Why: No need to treat gas for power option. Pertamina DOH Sumbagsel J Power Generation Option: yes Why: PLN 20kV distribution line within 3km. Flat open terrain . City Sedupi, within 5 km Possible barriers: Gas daily production rate 0.2 MMscfd.

Gas reserves > 10 yrs. May already be connected to pipeline Bureaucratic. Gas quality Power this region from major grid large power plant Reliable supply already.



C-23



Pipeline Option: yes Why: Pertamina pipeline within 5km Flat open terrain. Possible barriers: Gas daily production rate 0.2 MMscfd.

Gas reserves > 10 yrs. May already be connected to pipeline Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: yes Why: Pipeline option will require gas treatment to pipeline specification. Within 3 km of main road Reserves Possible barriers: Gas daily production rate 0.2 MMscfd. Gas may already be committed. Bureaucratic. Gas quality Commercial PetroChinaSulawati

A Power Generation Option: yes Why:

Regional power generation by small Diesel genset. Can also connect to grid at 18 km away

Flat open terrain . City Seget, within 18 km Possible barriers: Small daily production Reserves. Bureaucratic. Gas quality


C-24




Pipeline Option: yes Why: Connect to pipeline within 17km Flat open terrain. Possible barriers: Low daily production Pipeline to connect may already be full. Reserves. Bureaucratic. Gas quality - may need treatment to pipeline specification. Commercial Pipeline entry pressure, Pipeline block valve location as entry point unknown.

LPG Option: no Why: Reserves.

C-25


APPENDIX D: TECHNOLOGY SCREENING MODEL

D-1


Energy Price Inputs

All values in 2006 constant termsReal economic discount rate = 10%

Diesel price = 117% of the MOPS Brent Crude price FOBFreight = 10.72% of the base diesel price, to give C&F price

Insurance = 0.11% of the C&F price, to give CIF priceDistribution = 5.00% of the CIF price, to give total delivered price

Calorific value of 1 mscfd of gas = 1,100,000 btuCalorific value of 1 li of diesel = 34,784 btu

Ratio gas (USD/mscfd) to diesel (USD/li) prices = 0.085 0.085 0.157Generating capacity LRMC = 0.016 USD/kWh (based on 2005 PLN Cost of Service report)

Energy LRMC = 0.036 USD/kWh (based on 2005 PLN Cost of Service report)

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016MOPS Brent Crude, USD/bbl 70 75 60 50 50 55 60 65 70 75 80Diesel price, USD/li 0.60 0.64 0.51 0.43 0.43 0.47 0.51 0.56 0.60 0.64 0.69Gas price, USD/mscfd 5.95 6.38 5.10 4.25 4.25 4.68 5.10 5.53 5.95 6.38 6.80Electricity price, USD/kWh 0.106 0.112 0.093 0.080 0.080 0.087 0.093 0.100 0.106 0.112 0.119

MOPS Brent Oil Price Forecast

0102030405060708090

2006 2008 2010 2012 2014 2016

Year

Con

stan

t 200

6 U

SD p

er b

bl

Power Generation

Gas availablility 1 mmscfdCorresponding Genset size 4.7 MWHours per year of operation 7008 hoursDistance to existing 20 kV line 3 kmCost per km of power line 20,000 USD/kmO&M as % of Genset cap cost 5%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Costs

Genset 2,942,215Power line 60,000

O&M 147,111 147,111 147,111 147,111 147,111 147,111 147,111 147,111 147,111 147,111 147,111

RevenueValue of electricity produced 3,505,819 3,718,436 3,080,585 2,655,351 2,655,351 2,867,968 3,080,585 3,293,202 3,505,819 3,718,436 3,931,053

Cash Flow 356,493 3,571,325 2,933,474 2,508,240 2,508,240 2,720,857 2,933,474 3,146,091 3,358,708 3,571,325 3,783,942

Net Present Value 17.4 million USD

Assumptions: Gas avail.No gas processing required 17 3 30Overnight construction 0.5 8.3 7.8No financing charges 5 93.0 92.5No economic value of CDM 10 189.9 189.4No economic value of input gas 15 287.7 287.2

25 485.1 484.650 983.1 982.6

Power Generation(km to existing 20 kV line)

Pipeline

Gas availablility 1 mmscfdHours per year of operation 8000 hoursDistance to existing pipeline 5 kmCost per km of pipeline 120,000 USD/km; assumes 6" pipeO&M as % of total cap cost 5%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Costs

Compressors 393,000Dehydration Unit 1,039,500

Entry metering & control 50,000Receving facilities 50,000

Pipeline 600,000O&M 106,625 106,625 106,625 106,625 106,625 106,625 106,625 106,625 106,625 106,625 106,625

RevenueValue of gas delivered 1,983,333 2,125,000 1,700,000 1,416,667 1,416,667 1,558,333 1,700,000 1,841,667 1,983,333 2,125,000 2,266,667

Cash Flow (255,792) 2,018,375 1,593,375 1,310,042 1,310,042 1,451,708 1,593,375 1,735,042 1,876,708 2,018,375 2,160,042


Assumptions: Gas avail.Compression to 30 bar required 9 3 30Overnight construction 0.5 4.5 2.5No financing charges 5 50.3 30.3No economic value of CDM 10 102.3 62.3No economic value of input gas 15 154.6 94.6No chilling or sweetening required 25 259.7 159.7

50 523.7 323.8

Pipeline(km to existing pipeline)

CNG

Gas availablility 1 mmscfdHours per year of operation 8000 hoursAvg distance to point of use 50 kmCost of storage 1.125 USD/scfOwn gas use 1.6%O&M as % of total cap cost 5%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Costs

Initial compressors 393,000Dehydration Unit 1,039,500

Chilling Unit 1,036,200High pressure compressors 397,500

On-site storage (1 day) 1,125,000Delivery units 665,900

Customer storage (3 days) 3,375,000O&M 232,855 232,855 232,855 232,855 232,855 232,855 232,855 232,855 232,855 232,855 232,855


Cash Flow (6,313,355) 1,858,145 1,439,945 1,161,145 1,161,145 1,300,545 1,439,945 1,579,345 1,718,745 1,858,145 1,997,545


Assumptions: Gas avail.Initial compression to 30 bar required 3 20 150Overnight construction 0.5 0.7 0.3No financing charges 5 22.5 18.1No economic value of CDM 10 47.7 39.0No economic value of input gas 15 73.3 60.3No sweetening required 25 124.9 103.3

50 255.3 212.0

CNG(avg km to point of use)

LNG

Gas availablility 1 mmscfdHours per year of operation 8000 hoursDistance to point of consumption 150 kmOwn gas use 20%Tranport O&M + insur as % of cap cost 10%Liquification O&M as % of cap cost 3%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Costs

Liquification facilities 2,911,400LNG production storage (1 day) 195,100

Delivery units 396,800Regas & 2 days storage at user's site 702,000

Transport O&M & insurance 39,680 39,680 39,680 39,680 39,680 39,680 39,680 39,680 39,680 39,680 39,680Liquification O&M 114,255 114,255 114,255 114,255 114,255 114,255 114,255 114,255 114,255 114,255 114,255


Cash Flow (2,772,568) 1,546,065 1,206,065 979,398 979,398 1,092,732 1,206,065 1,319,398 1,432,732 1,546,065 1,659,398


Assumptions: Gas avail.Overnight construction 5 20 150No financing charges 0.5 1.8 1.7No economic value of CDM 5 30.9 29.8No economic value of input gas 10 65.2 63.0

15 100.4 97.125 172.5 166.950 358.8 347.7

LNG(avg km to point of use)

Gas avail.(mmscfd) 3 30 3 30 20 150 20 150

0.5 8.3 7.8 4.5 2.5 0.7 0.3 1.8 1.75 93.0 92.5 50.3 30.3 22.5 18.1 30.9 29.8

10 189.9 189.4 102.3 62.3 47.7 39.0 65.2 63.015 287.7 287.2 154.6 94.6 73.3 60.3 100.4 97.125 485.1 484.6 259.7 159.7 124.9 103.3 172.5 166.950 983.1 982.6 523.7 323.8 255.3 212.0 358.8 347.7

CNG LNG(avg km to point of use) (avg km to point of use)

Power Generation Pipeline(km to existing 20 kV line) (km to existing pipeline)

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0 2 4 6 8 10

Flare Gas Availability, mmscfd

Net

Pre

sent

Val

ue, 2

006

mill

ion

USD

Power Gen (3 km)Power Gen (30 km)Pipeline (3 km)Pipeline (30 km)CNG (20 km)CNG (150 km)LNG (20 km)LNG (150 km)

APPENDIX E: FINANCIAL & ECONOMIC MODEL

E-1


Appendix E

<Field Name>

Gas Availability & Field CharacteristicsHours per year of operation 8,000Energy content of rich gas, mmBTU/mscf 1.128Mole % of C3+C4 5%C3+C4 availability, mt/mmscf rich gas 3.05Energy content of lean gas, mmBTU/mscf 1.035Carbon equivalent of rich gas stream 62.7 mt CO2 eq/mmscf

Distance to existing 20 kV line 15 kmDistance to existing pipeline 30 km

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Total (Rich) Gas Production, mmscfd 5 4.75 4.51 4.29 4.07 3.87 3.68 3.49 3.32 3.15Lean Gas Production, mmscfd 4.75 4.51 4.29 4.07 3.87 3.68 3.49 3.32 3.15 2.99C3+C4 Production, mt/day 15.25 14.49 13.76 13.07 12.42 11.80 11.21 10.65 10.12 9.61t CO2 eq per year 114,428 108,706 103,271 98,107 93,202 88,542 84,115 79,909 75,914 72,118

Energy Price InputsAll values in 2006 constant terms

Real economic discount rate = 10%Real financial discount rate = 8%

Diesel price = 117% of the MOPS Brent Crude price FOBLPG price = 5.95 of MOPS Brent Crude Price FOB

Freight = 10.72% of the base diesel price, to give C&F priceInsurance = 0.11% of the C&F price, to give CIF price

Distribution = 5.00% of the CIF price, to give total delivered price

Calorific value of 1 li of diesel = 34,784 btuRatio gas (USD/mscfd) to diesel (USD/li) prices = 0.085 0.085 0.17

Gas sales price at pipeline = 3.00 USD/mmBTUPrice for gas for power gen = 30% of gas sales price at pipeline

Price for LPG at extraction as % of CIF = 80%

Generating capacity LRMC = 0.016 USD/kWh (based on 2005 PLN Cost of Service report)Energy LRMC = 0.036 USD/kWh (based on 2005 PLN Cost of Service report)

Electricity bulk tariff = 60.0% of LRMC

Development Cost without LPG = 500,000 USDDevelopment Cost with LPG = 750,000 USD

Value of CERs = 7.50 USD/t CO2 eq

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Economic PricesMOPS Brent Crude, USD/bbl 70 75 60 50 50 55 60 65 70 75 80Diesel price CIF, USD/li 0.60 0.64 0.51 0.43 0.43 0.47 0.51 0.56 0.60 0.64 0.69Gas price, USD/mmBTU 5.95 6.38 5.10 4.25 4.25 4.68 5.10 5.53 5.95 6.38 6.80Generation + Energy LRMC, USD/kWh 0.106 0.112 0.093 0.080 0.080 0.087 0.093 0.100 0.106 0.112 0.119LPG CIF, USD/mt 626.54 661.18 557.26 487.98 487.98 522.62 557.26 591.90 626.54 661.18 695.82Value of carbon reduction, USD/t CO2 eq 7.50 6.94 6.43 5.95 5.51 5.10 4.73 4.38 4.05 3.75 3.47

Financial Prices to Producer (excludes VAT)Pipeline gas, USD/mmBTU at change of custody 3.00 2.78 2.57 2.38 2.21 2.04 1.89 1.75 1.62 1.50 1.39Bulk electricity tariff, USD/kWh 0.064 0.067 0.056 0.048 0.048 0.052 0.056 0.060 0.064 0.067 0.071LPG at point of extraction, USD/mt 479.22 513.45 410.76 342.30 342.30 376.53 410.76 444.99 479.22 513.45 547.68Genset gas purchased, USD/mmBTU 0.90 0.83 0.77 0.71 0.66 0.61 0.57 0.53 0.49 0.45 0.42CERs, USD/t CO2 eq 7.50 6.94 6.43 5.95 5.51 5.10 4.73 4.38 4.05 3.75 3.47

3_Field Analysis v4.xls Page 1

Appendix E

Power Generation

2007 gas availablility 5 mmscfdCorresponding nominal genset size 23.6 MW sized for full gas availabilityGenset derating 0.0% - is decrease in effective genset size; + is increaseEffective Genset Output 23.6Hours per year of genset operation 7008 hoursCost per km of power line 20,000 USD/kmO&M as % of Genset cap cost 5%Duty on Genset 10.0%

Economic Analysis 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

CostsGenset 9,966,980

Power line 300,000Development Cost 500,000

O&M 498,349 498,349 498,349 498,349 498,349 498,349 498,349 498,349 498,349

RevenueValue of electricity produced 15,402,925 13,276,754 13,276,754 14,339,839 15,402,925 16,466,010 17,529,095 18,592,181 19,655,266

Value of carbon reduction 559,188 491,878 432,671 380,590 334,778 294,481 259,034 227,854 200,427

Cash Flow -10,766,980 15,463,764 13,270,283 13,211,076 14,222,080 15,239,354 16,262,142 17,289,780 18,321,686 19,357,344


Assumptions: 136% t CO2 valNo gas processing required 71 0.036 0.036Overnight construction 0 69.1 69.1No financing charges 7.5 71.1 71.1No economic value of CDM 15 73.1 73.1No economic value of input gas

Financial Analysis 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016


Power line 300,000Development Cost 500,000

Cost of Gas 1,207,311 1,061,986 934,155 821,710 722,801 635,797 559,266 491,947 432,731O&M 498,349 498,349 498,349 498,349 498,349 498,349 498,349 498,349 498,349


Value of CERs 559,188 491,878 432,671 380,590 334,778 294,481 259,034 227,854 200,427

Cash Flow -11,763,678 8,095,283 6,897,595 6,966,220 7,664,435 8,355,383 9,039,941 9,718,877 10,392,867 11,062,507


Assumptions: t CO2 valNo gas processing required 38 60% 60%Overnight construction 0 35.8 35.8No financing charges 7.5 38.0 38.0No economic value of CDM 15 40.2 40.2

Power Generation(energy LRMC)

Power Generation(electricity tariff as % of LRMC)


Appendix E

Power Generation with LPG

2007 gas availablility 5 mmscfdCorresponding nominal genset size 21.7 MW sized for lean gas availabilityGenset derating 0.0% - is decrease in effective genset size; + is increaseEffective Genset Output 21.7Hours per year of genset operation 7008 hoursHours per year of LPG extraction 8000 hoursDistance to existing 20 kV line 15 kmCost per km of power line 20,000 USD/kmO&M as % of Genset cap cost 5%O&M as a % of LPG cap costDuty on Genset & LPG equipment 10.0%Energy needed for LPG extraction 3.0%



Dehydration unit 2,730,276Chilling unit 2,221,000

LPG extraction cost 2,514,909Power line 300,000

Development cost 750,000O&M 468,401 468,401 468,401 468,401 468,401 468,401 468,401 468,401 468,401


Value of LPG production 2,691,108 2,238,712 2,126,777 2,163,864 2,191,925 2,211,770 2,224,151 2,229,764 2,229,256Value of carbon reduction 542,412 477,122 419,691 369,172 324,735 285,646 251,263 221,018 194,414

Cash Flow -17,884,198 16,958,915 14,481,963 14,312,596 15,278,797 16,242,054 17,202,444 18,160,075 19,115,077 20,067,597


Assumptions: t CO2 valNo gas processing required 70 0.036 0.036Overnight construction 0 68.3 68.3No financing charges 7.5 70.2 70.2No economic value of CDM 15 72.2 72.2No economic value of input gas



Dehydration unit 3,003,303Chilling unit 2,443,100

LPG extraction cost 2,766,400Power line 300,000

Development cost 750,000Cost of Gas 1,070,216 941,394 828,078 728,402 640,724 563,600 495,759 436,084 383,593

O&M 468,401 468,401 468,401 468,401 468,401 468,401 468,401 468,401 468,401


Value of LPG produced 1,586,891 1,256,289 1,193,474 1,247,181 1,292,533 1,330,232 1,360,929 1,385,232 1,403,701Value of CERs 542,412 477,122 419,691 369,172 324,735 285,646 251,263 221,018 194,414

Cash Flow -19,567,618 9,106,964 7,664,334 7,657,404 8,348,048 9,024,420 9,687,935 10,339,870 10,981,382 11,613,519


Assumptions: t CO2 valNo gas processing required 35 60% 60%Overnight construction 0 32.8 32.8No financing charges 7.5 34.9 34.9No economic value of CDM 15 37.0 37.0

Power Gen & LPG(energy LRMC)

Power Gen & LPG(electricity tariff as % of LRMC)


Appendix E

Pipeline

2007 gas availablility 5 mmscfdHours per year of operation 8,000 hoursCost per km of pipeline 120,000 USD/km; assumes 6" pipeO&M as % of total cap cost 5%Duty on compressors, dewatering & controls 10%Compression energy consumption 1.5%


CostsCompressors 1,816,600

Dehydration Unit 2,730,276Entry metering & control 250,000

Receving facilities 250,000Pipeline 3,600,000


RevenueValue of gas delivered 8,669,340 6,863,227 6,520,066 6,813,469 7,061,231 7,267,184 7,434,888 7,567,654 7,668,556


Cash Flow -9,146,876 8,925,496 7,036,508 6,620,448 6,849,726 7,041,083 7,197,420 7,321,480 7,415,855 7,482,988


Assumptions: t CO2 eqCompression to 30 bar required 30 0.085 0.17Overnight construction 0 27.8 66.1No financing charges 7.5 30.2 68.6No economic value of CDM 15 32.7 71.1No economic value of input gasNo chilling or sweetening required



Dehydration Unit 3,003,303Entry metering & control 275,000





Cash Flow -9,626,563 4,628,251 4,019,105 3,483,283 3,011,957 2,597,366 2,232,678 1,911,889 1,629,713 1,381,502


Assumptions: t CO2 eqCompression to 30 bar required 8 3.00 3.00Overnight construction 0 5.6 5.6No financing charges 7.5 8.3 8.3No economic value of CDM 15 11.0 11.0

Pipeline(ratio gas to diesel price)

Pipeline(gas sales price)


Appendix E

Pipeline with LPG

2007 gas availablility 5 mmscfdHours per year of operation 8000 hoursDistance to existing pipeline 30 kmCost per km of pipeline 120,000 USD/km; assumes 6" pipeO&M as % of total cap cost 5%Duty on comp's, dewatering, LPG & controls 10%Energy consumption for compression 1.5%Energy consumption of LPG extract. 3%



Dehydration Unit 2,730,276Chilling unit 2,221,000

LPG Extraction Unit 2,514,909Entry metering & control 250,000




Value of LPG produced 2,571,220 2,138,978 2,032,029 2,067,463 2,094,274 2,113,236 2,125,065 2,130,428 2,129,943Value of carbon reduction 667,845 587,456 516,744 454,543 399,830 351,702 309,368 272,129 239,373

Cash Flow -14,132,785 10,979,185 8,714,625 8,204,097 8,461,932 8,674,359 8,844,967 8,977,135 9,074,042 9,138,675


Assumptions: t CO2 eqCompression to 30 bar required 35 0.085 0.17Overnight construction 0 32.2 69.4No financing charges 7.5 34.6 71.8No economic value of CDM 15 37.0 74.2No economic value of input gasNo chilling or sweetening required



Dehydration Unit 3,003,303Chilling unit 2,443,100

LPG Extraction Unit 2,766,400Entry metering & control 275,000




Value of LPG produced 1,516,195 1,200,321 1,140,305 1,191,619 1,234,950 1,270,970 1,300,300 1,323,520 1,341,167Value of carbon reduction 667,845 587,456 516,744 454,543 399,830 351,702 309,368 272,129 239,373

Cash Flow -15,086,063 5,755,833 4,849,088 4,269,324 3,863,452 3,504,629 3,186,902 2,905,066 2,654,575 2,431,458


Assumptions: t CO2 eqCompression to 30 bar required 9 3.00 3.00Overnight construction 0 6.1 6.1No financing charges 7.5 8.7 8.7No economic value of CDM 15 11.3 11.3No economic value of input gas

Pipeline & LPG(ratio gas to diesel price)

Pipeline & LPG(gas sales price)


APPENDIX F: THE CLEAN DEVELOPMENT MECHANISM

This section discusses the potential of Certified Emission Reduction (CER) -- carbon credits earned from Clean Development Mechanism (CDM) Scheme -- that could be generated from gas flaring reduction projects in Indonesia. A brief overview of CDM and the process to secure the carbon credits is described including the costs associated to CDM process, followed by a historical fluctuation of the CER price, citing actual CER transactions where possible. The financial analysis is finally conducted by applying appropriate CER valuations and taking into account other costs associated to CDM process.

Growing concerns of climate change led to the adoption of the United Nations Framework on Climate Change Convention (UNFCCC) at the Earth Summit 1992, Rio de Janeiro, setting the stage for discussion on climate change issues ever since. Under a major milestone -- the Kyoto Protocol of the UNFCCC, 1997 -- developed countries listed in Annex B (hereinafter called the “Annex B countries”), committed to reduce their greenhouse gas (GHG) emissions with an aim to stabilize the concentration of GHG in the atmosphere to a level that does not cause harm to the environment.

CDM provides flexibility under the Kyoto Protocol for Annex B countries to fulfill their commitments for reducing GHG emissions, and at the same time to assist non Annex-B countries, which are mostly developing countries, in achieving sustainable development. CDM is the only such mechanism that involves developing countries. Under the Kyoto Protocol, developing countries have no obligation to constrain their GHG emissions, but may, on a voluntary basis, contribute to global emission reductions by hosting CDM projects that help Annex B countries meet their reduction targets.

CDM is a project-based mechanism where the emission reductions are generated through specific projects. It is intended to promote investment in projects in developing countries. CDM projects must be validated, the projects must be registered, their emissions reductions must be verified, and then the verified emission reductions must be certified. Only the certified emission reductions can be used by Annex B countries to comply with their emission reduction commitments.

The CDM project cycle consists of several steps as follows:

Step 1: Project Development by the Project Proponent: The project proponent (PP) first identifies the project idea and conducts an initial evaluation of the eligibility and feasibility of developing the project. This evaluation will involve development of a Project Design Document (PDD) consisting of description of the baseline, baseline and project emission calculations, emission reduction calculations, and monitoring and verification protocol. The PDD is a formal requirement of the CDM Executive Board (CDM EB) and the format is also given by the CDM EB. The determination of baseline is developed based on the approved baseline methodology by the CDM EB. In the absence of an approved methodology, the PP may propose a new baseline methodology for evaluation and consideration by the CDM EB.

CDM EB has approved a methodology for gas flaring reduction project based on the Rang Dong Oil Field Associated Gas Recovery and Utilization Project, Vietnam, whose baseline study, monitoring and verification plan and project design document belong to Japan

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F: The Clean Development Mechanism

Vietnam Petroleum Co. Ltd. Any PP who intends to develop gas flaring reduction projects and is interested to claim Emission Reduction Credits from CDM scheme may use the methodology to build the PDD of the projects.

Step 2: Validation and Registration: PP seeks validation by a Designated Operation Entity (DOE) –an entity accredited by CDM EB to conduct CDM project validation. Validated projects will be then registered under CDM project registry.

Step 3: Project Monitoring: The emission performance of the project is monitored through crediting lifetime of the project using the monitoring methodology and monitoring plan (Monitoring and verification protocol, MVP) described in the project PDD. This is conducted on the basis of data collected on emission reductions environmental and social impacts and other operational information. MVP reports are submitted to DOE for verification as a basis for the issuance of CER.

Step 4: Verification, Certification and Issuance: Once the emission reductions verified by DOE, the emission reductions can be certified and the CER is issued to appropriate parties.

The initial CDM project evaluation, development of baseline and monitoring plan, validation and registration activities require certain cost while development of the PDD does not guarantee that the project will be successfully validated and registered. These costs associated to the CDM project cycle are called “transaction costs”. Exhibit E.1 illustrates the general transaction costs incurred for a CDM project in 2004. Following the dynamic CDM market in 2005-2006, this cost has been decreasing ever since. In most cases, PP would not take risk to bear the transaction costs. To date, most buyers take the initiatives to bear the cost of PDD development, validation and registration but they have the advantage to buy the ER in a forward contract.

Exhibit E.1: Transaction cost of a CDM Project, 2004

Source: Carbon Finance (2004)

Task Cost (€)General project/enterprise due dilligence

20,000

Development of Baseline and PDD

20,000

Monitoring and Verification Protocol

10,000

New Methodology 15,000Stakeholder Consultation 5,000Validation of PDD 15,000First and Second Verification 15,000

Transaction Negotiation and Contracts

15,000

Registration costs to CDM Executive Board

15,000

First baseline revision 10,000

Second baseline revision 10,000

Total cost for 7 years x 3 crediting period

150,000

In general, the PP would prepare a 7-8 page Project Idea Note (PIN) consisting an overview of a projects in terms of type of project, potential of emission reduction, sources

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of financing, and laws and regulations related to the project. This PIN is not required in the formal modalities and procedures of CDM Executive Board (CDM EB), but it is normally prepared to be distributed among CER buyers for initial evaluation. Shall a buyer attracted with a PIN, the buyer would contact the PP for further negotiation for an Emission Reduction Purchase Agreement (ERPA).

Volume of CER transactions has been increasing from about 97 MtCO2e in 2004 to about 346 MtCO2 in 2005. In the first quarter of 2006, about 76 MtCO2e CER contracts were secured (World Bank, 2006). Price of CERs in primary market transactions appreciated considerably from an average of US$ 5.15 in 2004, to US$ 7.04 in 2005 and US$ 11.56 in the first three months of 2006.

PointCarbon is another information source of CER prices, and has cited more optimistic values based on CER transactions published in their weekly CDM/JI Monitor. Exhibit E.2 shows the actual transaction price of CDM projects as cited by PointCarbon in their weekly CDM/JI Monitor during January-May 2006. Four (4) issues of CDM/JI monitor were taken as sources for Exhibit E.2. The transacted CER is generally in the range of about 8-15 but in some cases, the price range increase to about € 26.

The market share of CDM credits from developing countries was about 49.2 % of overall carbon market volumes transacted globally. In the first three months of 2006, CDM’s market share of overall carbon market volume was about 27.2%. The ER buyers of project-based transactions, which include both CDM and JI, are largely dominated by European-based buyers and Japanese buyers.

Exhibit E.2: Fluctuation of CER Price in During January

Source Volume transacted

(tCO2e)

Delivery Price category*

Price range (€)

CDM/JI Monitor, 24 January 2006

2,600,000 2008-2013 3 9-14

CDM/JI Monitor, 21 February 2006

1,000,000 2007-2010 2 6-10


600,000 2009-2013 3 9-14


2,700,000 2009-2013 2 6-10


2,600,000 2008-2013 3 9-14

CDM/JI Monitor, 7 March 2006

8,000,000 2007-2013 3 10-16

CDM/JI Monitor, 2 May 2006

1,000,000 2007-2012 4 16-26


25,782 2005-2007 4 16-26


2,000,000 2007-2014 2 7-15

*Price Category as developed by PointCarbon: 1: The seller does its utmost to deliver a flexible/non-firm volume, whereas the buyer commits to buy what the seller delivers. 2: The seller does its utmost to deliver a flexible/non-form volume, whereas the buyer commits to buy if the

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seller delivers. The contract is only valid on a set of preconditions. 3: The seller guarantees to deliver a firm volume; the buyer commits to buy if the seller delivers. The contract is only valid on a set of preconditions and usually has a strong force majeure clause. 4: The seller guarantees to deliver a firm volume, and the buyer guarantees to buy if seller delivers.

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