lpg associated gas

UNFCCC/CCNUCC CDM Executive Board Page 1

PROJECT DESIGN DOCUMENT FORM FOR CDM PROJECT ACTIVITIES (F-CDM-PDD)

Version 04.0

PROJECT DESIGN DOCUMENT (PDD)

Title of the project activity Sukowati-Mudi (Tuban) LPG Associated Gas Recovery and Utilization Project

Version number of the PDD 01 Completion date of the PDD 19/04/2012 Project participant(s) Private entity: PT. Gasuma Federal Indonesia

Private entity: Agrinergy Pte Ltd Private entity: Sumitomo Corporation

Host Party(ies) Republic of Indonesia Sectoral scope and selected methodology(ies) Sectoral scope 10: Fugitive emission from fuels

Approved baseline methodology AM0009 version 05.0.1: Recovery and utilization of gas from oil wells that would otherwise be flared or vented

Estimated amount of annual average GHG emission reductions

57,223


SECTION A. Description of project activity A.1. Purpose and general description of project activity The project activity is the construction of a new facility to recover and utilize the flared associated gas located at Mudi-Sukowati Oil Fields, East Java, Indonesia, to produce the saleable hydrocarbon products namely lean gas, condensate and LPG. The project activity is undertaken by PT. Gasuma Federal Indonesia (GFI) (hereinafter referred to as Project Proponent), a joint venture between PT. Yudistira Energy and PT. Gasuma Corporindo. In the absence of the project activity (the baseline scenario) and the scenario existing prior to the start of the implementation, the associated gas would be flared. Flaring of associated gas is seen as common practice in Indonesian oil production, although the practice has negative environmental impacts and wastes energy resources. The gas flaring activity at Mudi-Sukowati oil fields has become a major environment problem since 2006 due to the high content of CO2 and H2S (36%) of the associated gas flared. The effort to utilise this associated gas was initially made in 2007 with the signing of associated Gas Purchase Agreement (GPA) between PT Gasuma Corporindo and PT Pertamina EP, PT Pertamina, Petrochina International Java Ltd and PT Medco E&P Tuban as the oil field operators. However, due to the financial crisis in 2008, the effort to construct the gas processing plant facility was halted and the associated gas is still flared. To overcome the gas flaring issue, BP Migas (The Upstream Oil and Gas Executive Agency) as Indonesian Oil and Gas Regulatory Body gave permit to PT Gasuma Corporindo to continue the GPA with several adjustments on GPA articles, including the provision to add in PT. Pertagas (Pertamina Gas) as the project monitoring body and PT Yudistira Energy as technical-support shareholder to GFI to ensure the implementation of the project activity. The project facility was redesigned and the construction was restarted in April 2011. The project is expected to be commissioned in May 2012. The project activity is designed to process approximately 12 MMSCFD of associated gas from Mudi Sukowati Field. It encompasses the establishment of compressor, condensate recovery plant, amine plant, regenerative thermal oxidizers (RTO), and gas processing plant. Due to its high content of CO2 and H2S (36%), the associated gas (sour gas ) is first processed into sweet gas. The processed sweet gas is then fed to the gas processing plant for further processing into lean gas, LPG and condensate. The project activity is categorized in the sectoral scope 10 Fugitive emissions from fuels (solid, oil and gas) and it reduces the GHG emissions from the substitution of fossil fuel with gas recovered from the associated gas. The project activity is expected to reduce an average of 57,223 tonnes of CO2e per annum. The emission reduction varies from 104,056 in the first year and then decreases to 23,820 in the final year. This variation in the emission reduction is due to reducing gas availability estimate. Contribution to sustainable development Environmental sustainability: This project will contribute to environmental sustainability by the reduction of CO2 and H2S emission as the result of avoiding gas flare. Furthermore, by producing LPG, condensate and lean gas the project activity provides clean source of energy to the consumers, displacing other higher carbon intensive fossil fuels consumption. Economy and social sustainability: The proposed project activity will benefit the local community by generating the employment potential during construction and operation phase. Moreover, the project activity will contribute to increased

UNFCCC/CCNUCC CDM Executive Board Page 3 availability of lean gas, LPG, and condensate to various industrial consumers. This will help to secure supply of reliable and quality energy resources to local industries. Technological sustainability: A qualified and experienced technology provider from Annex I country which has been providing services in oil and gas industry and similar activities is contracted and deployed for the project activity. The project activity contributes to the technological sustainability through the utilization of a proven technology and the transfer of knowledge and technical skill to the host country via employee training. A.2. Location of project activity A.2.1. Host Party(ies) Republic of Indonesia A.2.2. Region/State/Province etc. East Java Province, Tuban District A.2.3. City/Town/Community etc. Soko Sub District, Sumurcinde Village A.2.4. Physical/Geographical location The geographical coordinates set of the Mudi Sukowati LPG plant is: Latitude : 7 6'24.97"S Longitude : 11157'58.53"E

Figure A.2.1: Location map of Mudi Sukowati LPG Plant

UNFCCC/CCNUCC CDM Executive Board Page 4 A.3. Technologies and/or measures Pre-project scenario The baseline scenario is the continuation of current practice where the associated gas is flared and the operation of the existing oil and gas infrastructure is continued without any other significant changes, thus it is identical to the scenario existing prior to the implementation of the project activity.

Figure. A.3.1. Pre-project (baseline) scenario Project Activity The purpose of project activity is to utilize approximately 12 MMSCFD of associated gas from Mudi Sukowati Field which has high content of CO2 and H2S (36%). The project activity encompasses the new establishment and operation of compressor, condensate recovery plant, amine plant, compressor, and gas processing plant, recovering the associated gas emitted from the nearby oil wells, to produce LPG, condensate and lean gas. The detailed list of main equipments that will be installed by the project activity is presented in the table below: Table. A.3.1. List of main equipments Equipment name Quantity Specification Compressor Package 1 unit Designed capacity of 15 MMSCFD

(424,750 Sm3 per day) Condensate Recovery Package 1 unit Designed capacity of 15 MMSCFD

(424,750 Sm3 per day) Generator Set (gas engine) 4 unit 2 MW each ( 380 V, 3 Ph, 50 Hz) Back up generator set (gas) 1 unit 2 MW ( 380 V, 3 Ph, 50 Hz) Back up generator set (diesel) 3 unit 1 MW each Regenerative Thermal Oxydizer Package

1 package

Gas Processing Plant (LPG) 1 package Pipelines

1 set Feed gas pipeline 1 set Sweet/lean gas pipeline 1 set Condensate pipeline

Storage and loading facility - Condensate tanks 4 unit 260 m3 each - Off spec condensate tank 1 unit 170 m3

Amine Plant package 1unit

Mudi Sukowati Oil Fields

Associated gas

Flaring

CO2

UNFCCC/CCNUCC CDM Executive Board Page 5 The average lifetime of the gas processing facility is 20 years. This is in line with the Decree of Ministry of Finance No 96/2009 which defines the equipment lifetime for Oil and Gas Industry of 20 years, taking into account the standard of average technical lifetime of equipment in the industry. By recovery and utilization of associated gas to produce LPG, condensate and lean gas, the project activity displaces the use of other fossil fuel sources and therefore the CO2 emissions, are reduced. The project emissions are derived from the lean gas combustion for the process and also for the use of electricity. Besides the gas generator set as the main electricity generator system, fossil fuel combustion in the project activity is also envisaged from the emergency diesel generator system located in the project site as the back-up power. For ex-ante estimations the project emissions from the use of diesel in the emergency diesel generator system has been considered zero. The parameters for the calculation of same will be monitored ex-post and the project emissions taken into account as actual. The detail monitoring equipments and their location in the system are described in the figure below. Figure A.3.1 Monitoring equipments and location a Meter to measure the sour gas consumed by thermal oxidizer b Meter to measure the sour gas consumed by heater at condensate recovery c Meter to measure the sour gas consumed by heater at amine plant d Electricity meter to measure the electricity consumption supplied by gas generator e Electricity meter to measure the electricity consumption supplied back-up diesel generator f Meter to measure recovered gas entering the gas processing plant (sweet gas) g Meter to measure the sour gas consumed by heater at gas processing plant The project activity is using environmentally safe and sound technology and proven equipments. For amine plant package, the main equipment to remove CO2 and H2S from the associated gas, the project activity has chosen Propak, a technology provider which has been servicing the similar project activities worldwide for years. Similarly, for refrigeration package in the gas processing plant, Austcold is used. The technology providers will provide training for employees and engineers of GFI the during the commissioning period to ensure the know-how is transferred to the host party.

f

Sukowati Mudi Oil Field

Pretreatment

Amine plant

Thermal oxidizer

Gas processing plant

Generator set

Lean gas LPG Condensate

Flaring

Project boundary In the absence of project activity

Gas pipeline users

Diesel Generator

Back up

a bCondensate recov ery

compressor

c

d

eg

f

UNFCCC/CCNUCC CDM Executive Board Page 6 A.4. Parties and project participants

Party involved (host) indicates a host Party

Private and/or public entity(ies) project participants

(as applicable)

Indicate if the Party involved wishes to be considered as

project participant (Yes/No)

Republic of Indonesia (host) Private entity: PT. Gasuma Federal Indonesia

No

United Kingdom of Great Britain and Northern Ireland

Private entity: Agrinergy Pte Ltd

No

United Kingdom of Great Britain and Northern Ireland

Private Entity: Sumitomo Corporation

No

Contact details as listed in Appendix 1. A.5. Public funding of project activity The project has not received any public funding or Official Development Assistance (ODA) from Annex I Parties.


SECTION B. Application of selected approved baseline and monitoring methodology B.1. Reference of methodology The selected methodology: Approved baseline methodology AM0009 Recovery and utilization of gas from oil wells that would otherwise be flared or vented (Version 05.0.1) This methodology also refers to the latest approved versions of the following tools:

- Tool for the demonstration and assessment of additionality (Version 06.0.0, EB 65, Annex 21) - Tool to calculate project or leakage CO2 emissions from fossil fuel combustion (Version 02, EB 41,

Annex 11) - Tool to calculate baseline, project and/or leakage emissions from electricity consumption (Version

01, EB 39, Annex 7) B.2. Applicability of methodology Methodology AM0009 version 05.0.1 is applicable for the project activity for the following reasons: Table B.2-1: Applicability of the Project Activity Applicability Project Activity The methodology is applicable to project activities that recover and utilise associated gas and/or gaslift gas from oil wells.

The project activity is the installation of new facility to recover and utilise associated gas from oil wells and hence it conforms to this criterion.

Under the project activity the recovered gas, after the pre-treatment (compression and phase separation) in movable or stationary equipment, is: Consumed on-site to meet energy demands; and/or Transported to a gas pipeline without prior

processing; and/or Transported to a processing plant where it is

processed into hydrocarbon products (e.g. dry gas, LPG and condensates). The dry gas is either (i) transported to a gas pipeline directly, or (ii) compressed to CNG first, then transported by

trailers/trucks/carriers and then decompressed and gasified again, before it finally enters the gas pipeline.

In the project activity, after the pretreatment (compression and phase separation) in a stationary equipment, the recovered gas is transported to a processing plant where it is processed into hydrocarbon products (LPG, lean gas and condensate). The dry gas then is transported to a gas pipeline directly. Hence this criterion is met.

The project activity does not lead to changes in the process of oil production, such as an increase in the quantity or quality of oil extracted, in the oil-wells within the project boundaries;

The project activity does not lead to changes in the process of oil production in the oil wells within the project boundaries. Hence this criterion is met.

The injection of any gases into the oil reservoir and its production system is allowed in the project activity only for the purpose of the gas-lift process;

The project activity does not involve the injection of any gases into the oil reservoir and its production system or any gas-lift process. Hence this criterion is met.

All recovered gas comes from oil wells that are in operation and are producing oil at the time of the recovery of the associated gas and/or gas-lift gas.

The project activity recovers gas from oil wells that are in operation and are producing oil at the time of the recovery of the associated gas. Hence this criterion is met.

The methodology is only applicable if the identified baseline scenario is: The continuation of the current practice of either

venting (scenario G1), flaring (scenario G2) of the

The identified baseline scenario of the project activity is the continuation of the current practice of flaring of the associated gas and the continued operation of the existing oil and gas


associated gas and/or gas-lift gas or on-site use of the partial amount of associated gas and/or gas-lift gas to meet on-site energy demands and rest of the gas are either vented or flared (scenario G3); and

The continued operation of the existing oil and gas infrastructure without any other significant changes (scenario P4); and

In the case where gas-lift is used under the project activity: the gas-lift gas under the baseline uses the same source as under the project activity and the same quantity as under the project activity (scenario 01).

infrastructure without any other significant changes, as detailed in the Section B.4.

The proposed project activity meets the applicability conditions of the tools referred to as follows: Table B.2-2: Applicability of the Tools Applicability of the tools Project Activity Tool to calculate project or leakage CO2 emissions from fossil fuel combustion version 02 - This tool can be used in cases where CO2 emissions

from fossil fuel combustion are calculated based on the quantity of fuel combusted and its properties.

The project activity calculates the CO2 emissions from lean gas combustion based on the quantity of lean gas combusted and its properties. Hence this criterion is met.

Tool to calculate baseline, project and/or leakage emissions from electricity consumption version 01 - The tool may be used in methodologies where

auxiliary electricity is consumed in the project and/or the baseline scenario. The tool can also be applied in situations where electricity is only consumed in the baseline or in the project or as leakage source.

- One out of the following three scenarios applies to the sources of electricity consumption: Electricity consumption from the grid, Electricity consumption from (an) off-grid fossil fuel fired captive power plant(s), Electricity consumption from the grid and (a) fossil fuel fired captive power plant(s)

- This tool is not applicable in cases where captive renewable power generation technologies are installed to provide electricity in the project activity, in the baseline scenario or to sources of leakage. The tool only accounts for CO2 emissions.

- The methodology AM0009 version 05.0.1

refers to this tool to calculate the project emissions from electricity consumption. Hence this criterion is met.

- The source of electricity consumption in the

project activity is from off-grid lean gas fired captive power plants. Hence this criterion is met.

- The project activity does not involve source of

electricity consumpiton from a captive renewable power generation. The tools is used to calculate CO2 emissions. Hence this criterion is met.

B.3. Project boundary

Source GHGs Included? Justification / Explanation


Bas

elin

e Combustion of fossil fuels at end-users that are produced from non-associated gas or other fossil sources

CO2 Yes Main source of emissions in the baseline.

CH4 No Excluded for simplification as per the methodology. This is conservative.

N2O No Excluded for simplification as per the methodology. This is conservative.

Proj

ect A

ctiv

ity

Energy use for the recovery, pre-treatment, transportation, and if applicable, compression/decompression, transportation of the recovered gas

CO2 Yes Main source of emissions in the project.

CH4 No Excluded for simplification as per the methodology. This emission source is assumed negligible.

N2O No Excluded for simplification as per the methodology. This emission source is assumed negligible.

As per the approved methodology, the project boundary encompasses:

- The project oil reservoir and oil wells where the associated gas and/or gas-lift gas is collected; - The site where the associated gas and/or gas-lift gas was flared or vented in the absence of the

project activity; - The gas recovery, pre-treatment, transportation infrastructure, including where applicable,

compressors; - The source of gas-lift gas.

Figure B.3.1: Project Boundary and SchematicIllustration of Project Activity

B.4. Establishment and description of baseline scenario

Sukowati Mudi Oil Field

Pretreatment

Amine plant

Thermal oxidizer

Gas processing plant

Generator set

Lean gas LPG Condensate

Flaring

Project boundary In the absence of project activity

Gas pipeline users

Diesel Generator

Back up

Condensate recov ery

compressor

UNFCCC/CCNUCC CDM Executive Board Page 10 According to the approved methodology AM0009 - version 05.0.1, the baseline scenario is identified by applying the following procedure: Step 1: Identify plausible alternative scenarios The project activity involves three components. Plausible alternative scenarios should include alternatives for the following components:

a. Plausible alternative baseline scenarios for the associated gas from the project oil wells b. Plausible alternative baseline scenarios for oil and gas infrastructure c. Plausible alternative baseline scenarios for the use of gas-lift

Table B.4-1: Plausible alternative baseline scenarios for the associated gas from the project oil wells G1 Release of the associated gas and/or

gas-lift gas into the atmosphere at the oil production site (venting).

Not plausible. The associated gas in Mudi Sukowati has high CO2 and H2S content. Venting of the associated gas is dangerous due to likelihood of explosion, life threatening, and environmental health. Venting of associated gas is not prohibited by Indonesian Law, however it is restricted under the law 1 . Alternative (G1) is therefore not a plausible baseline scenario and will not be considered further.

G2 Flaring of the associated gas and/or gas-lift gas at the oil production site.

Plausible. Prior to the implementation of the project activity, the associated gas from Sukowati Mudi oil fields would be flared. Alternative (G2) is a plausible baseline scenario.

G3 On-site use of the partial amount of associated gas and/or gas-lift gas to meet on-site energy and rest of the gas are either vented (G1) or flared (G2).

Not Plausible. Without prior processing of the associated gas, it would not be feasible to use the partial amount of associated gas on-site to meet on-site energy, due to its high CO2 and H2S content (50%). Alternative (G3) is not a plausible baseline scenario and will not be considered further.

G4 Injection of the associated gas and/or gas-lift gas into an oil or gas reservoir.

Not Plausible. Injection of the associated gas into the oil reservoir is not required due to sufficient pressure. Furthermore due to its unpredictable effectiveness 2 , gas injection is considered costly. Alternative (G5) is not a plausible baseline scenario and will not be considered further.

G5 The proposed project activity without being registered as a CDM project activity.

Plausible. The proposed project activity itself is technically feasible. However, without CDM revenue, this scenario would not be financially attractive as shown in the step 3 below.

G6 Recovery, transportation, and utilization of the associated gas and/or gas-lift gas as feedstock for manufacturing of useful products.

Not plausible. Recovery, transportation, and utilization of the associated gas gas as feedstock for manufacturing of useful products would not be feasible due to high content of H2S and CO2. Without prior processing, the composition of associated gas which is lower in methane number is not in preference as feedstock for manufacturing. Alternative (G6) is not a plausible baseline scenario and will not be considered further.

Table B.4-2: Plausible alternative baseline scenarios for oil and gas infrastructure 1 Source: Regulation from Ministry of Environment No. 13 Year 2009 2 http://fossil.energy.gov/programs/oilgas/eor

UNFCCC/CCNUCC CDM Executive Board Page 11 Alternatives Plausibility/Eligibility P1 Construction of a processing plant for

the purpose of processing the recovered gas, in the same way as in the project activity, without being registered as a CDM project activity.

Plausible. This scenario is technically feasible however it would not be financially attractive without being registered as a CDM project activity as shown in the step 3 below.

P2 Construction of a processing plant of a lower capacity than under the project activity, which processes only non-associated gas and does not process recovered gas.

Not plausible. There is no non-associated gas in Mudi Sukowati and therefore alternative (P2) is not a plausible baseline scenario and will not be considered further.

P3 Supplying recovered gas to an existing gas processing plant and constructing the necessary infrastructure, without being registered as a CDM project activity.

Not Plausible. There is no existing gas processing plant on-site before the implementation of project activiy and therefore supplying recovered gas to an existing gas processing plant and constructing the necessary infrastructure is not an applicable scenario and will not be considered further.

P4 Continuation of the operation of the existing oil and gas infrastructure without any other significant changes.

Plausible. In the absence of the project activity, the operation of the existing oil and gas infrastructure would be continued without any other siginificant changes. Alternative (P4) is a plausible baseline scenario and will be considered further.

P5 Supplying recovered gas to a gas pipeline without prior processing and without being registered as a CDM project activity.

Not plausible. Without prior processing, the composition of associated gas which is high in CO2 and H2S content and lower in methane number is not in preference to be compressed directly to the gas pipeline. Alternative (P5) is not a plausible baseline scenario and will not be considered further.

c. Plausible alternative baseline scenarios for the use of gas-lift The gas-lift is not used under the project activity; therefore the alternative baseline scenarios for the use of gas-lift are not applicable. Identified plausible alternative scenarios for each component are summarized below: Table B.4-3: Plausible alternative baseline scenarios for oil and gas infrastructure For the associated gas G2

G5 Flaring of the associated gas and/or gas-lift gas at the oil production site. The proposed project activity without being registered as a CDM project activity.

For Oil and gas infrastructure

P1

P4

Construction of a processing plant for the purpose of processing the recovered gas, in the same way as in the project activity, without being registered as a CDM project activity. Continuation of the operation of the existing oil and gas infrastructure without any other significant changes.

For the use of gas-lift Not applicable since no gas-lift system is used under the project activity.

UNFCCC/CCNUCC CDM Executive Board Page 12 Out of 4 combinations of the plausible alternatives above, the combination of G2 & P4 and G5 & P1 are deemed realistic and possible. The result of combinations is outlined in the following table as alternative 1 and alternative 2. Table B.4-4: Realistic combinations of the three components Alternative 1 G2 Flaring of the associated gas and/or gas-lift gas at the oil production site. P4 Continuation of the operation of the existing oil and gas infrastructure without any other significant

changes. Alternative 2 G5 The proposed project activity without being registered as a CDM project activity. P1 Construction of a processing plant for the purpose of processing the recovered gas, in the same way

as in the project activity, without being registered as a CDM project activity. Step 2: Evaluate legal aspects All the realistic and possible alternatives above are in compliance with all applicable legal and regulatory requirements taking into account the enforcement in the region and EB decisions on national and/or sectoral policies and regulations. Step 3 and Step 4 of the identification of the baseline scenario and additionality are carried out in the Section B.5. B.5. Demonstration of additionality Step 3: Evaluate the economic attractiveness of alternatives As recommended in AM0009 version 05.0.1, the identification of the alternative scenarios that are feasible in technical terms and are permitted by law and applicable regulatory requirements has been demonstrated in the section B.4. The economic attractiveness is assessed for alternatives (1) and (2) by determining an expected Internal Rate of Return (IRR) of each alternative scenario based on the latest approved version of the Tool for demonstration and assessment of additionality. Alternative 1 G2: Flaring of the associated gas and/or gas-lift gas at the oil production site, and P4: Continuation of the operation of the existing oil and gas infrastructure without any other significant changes. Economic attractiveness evaluation for Alternative 1 This alternative will not require any investment and penalty is not charged for gas flaring in Indonesia. Gas flaring activity is seen as a normal practice in the oil production industry as a way to dispose excess gas or to protect vessels or pipes from over-pressuring. Hence this alternative will not create additional cost nor additional revenue for the project owners. In this case the required return of the alternative refers to the return of benchmark. As also stated in point 19 of the Guidelines on the Assessment of Investment Analysis version 05: The benchmark approach is suited to circumstances where the baseline does not require investment or is outside the direct control of the project developer, i.e. cases where the choice of the developer is to invest or not to invest. The benchmark has been based on the average local investment lending rate charged by national private banks in Indonesia during the investment decision making for the project activity (end of March 2011-

UNFCCC/CCNUCC CDM Executive Board Page 13 April 2010)3,i.e. 13.29%, and the IRR of the project will be compared to this. As stated in point 12 of the Guidelines on the Assessment of Investment Analysis version 05: Local commercial lending rates or Weighted Average Costs of Capital (WACC) are appropriate benchmarks for a project IRR. The financial information used for benchmark determination is publicly available. The calculation of benchmark has been detailed in the spreadsheet that will be submitted with the PDD. Alternative 2 G5: The proposed project activity without being registered as a CDM project activity. P1: Construction of a processing plant for the purpose of processing the recovered gas, in the same way as in the project activity, without being registered as a CDM project activity. Economic attractiveness evaluation for alternative 2 This alternative is the project activity without CDM revenue, and its economic attractiveness is assessed by the project IRR calculation. The project IRR is determined using the main relevant parameters as follows: Table B.5-1: Main Financial Parameters No. Parameter Value Source 1. Investment cost USD 41,759,536 Feasibility Study Report 2. Plant Production rate Based on 12 MMSCFD

feed gas Feasibility Study Report

- LPG 40 ton per day - Condensate 600 bbl per day - Lean gas 4.9 MMSCFD 3 Sales price - LPG 746 USD per ton Feasibility Study Report - Condensate 59 USD per bbl Feasibility Study Report - Lean gas 5.75 - 6.1 USD/MMBTU Lean Gas Sales Agreement page

8 4. Feed gas purchase price 0.5 - 1.46 USD/MMBTU Feed gas sales purchase

agreement page 24 5. Operation and Maintenance cost 6,380,689 USD/year Feasibility Study Report 6. Inflation rate 4.79% Average inflation rate in the

past two years 7. Tax rate 25% Law of taxation in Indonesia Table B.5-2: Feed Gas Availability Estimation 4 Year 1 2 3 4 5 6 7 8 9 10 Feed Gas (MMSCFD) 12 12 11 8 6 4 4 3 3 3 In compliance with Guidelines on the assessment of investment analysis point 3 that In general a minimum period of 10 years will be appropriate, the financial analysis projection has been presented for 10 years, taking into account 20 years lifetime and the residual value for the remaining years has been added back into the cash inflow. The project IRR for the project activity without taking into account the CERs revenue is 3.32%, lower than the benchmark (13.29%) and highlights that the project activity is not financially feasible. 3http://www.bi.go.id/seki/tabel/TABEL1_26.xls 4 Based on Gas availability estimation by BP Migas

UNFCCC/CCNUCC CDM Executive Board Page 14 According to the methodology, the alternative scenario that is economically the most attractive course of action is considered as the baseline scenario; hence the alternative 1, wherein the activities of gas flaring and the operation of the existing oil and gas infrastructure are continued without any significant changes (G2 & P4), is considered as the baseline scenario. Sensitivity analysis To show that the conclusion regarding the economic attractiveness above is robust and to provide a valid argument in favour of additionality, a sensitivity analysis has been conducted in accordance with point 20 and 21 of the Guidelines on the Assessment of Investment Analysis version 05. Variables which constitute more than 20% of either total project cost or total project revenues, including the initial investment cost, or have a material impact on the analysis, have been identified below and been subjected to reasonable variation range of 10%:

1. Investment cost 2. Operation & Maintenance Cost 3. Feed gas amount 4. Condensate revenue 5. Lean gas revenue 6. LPG revenue

The impacts were analyzed in the range of 10% and the corresponding impacts have been highlighted in the table and graph below: Table B.5-6: Sensitivity Analysis Variable -10% -5% 0% 5% 10%

Investment cost 8.16% 5.58% 3.32% 1.32% -0.44% Operation & Maintenance Cost 10.51% 7.15% 3.32% -1.21% -6.81% Feed gas amount -6.01% -1.22% 3.32% 7.58% 11.58% Condensate revenue -1.07% 1.14% 3.32% 5.46% 7.55% Lean gas revenue -0.24% 1.56% 3.32% 5.03% 6.69% LPG revenue -0.09% 1.64% 3.32% 4.96% 6.56%

Figure B.2: Sensitivity Analysis

UNFCCC/CCNUCC CDM Executive Board Page 15 The results show that in the absence of CDM revenues, the variations between +10% and -10% of those parameters consistently support the conclusion that the project activity is unable to pass the benchmark and is not the most financially attractive alternative. In accordance with the methodology, if the IRR of the project activity is lower than the hurdle rate of the project participants and if the most plausible baseline scenario is not the project activity without being registered as a CDM project activity; the analysis should proceed to the step 4 of Common Practice Analysis. Step 4: Common practice analysis The following section demonstrates that the project activity is not a common practice in geographical area of Indonesia by drawing on version 06.0.0 of Tool for the demonstration and assessment of additionality for demonstration of common practice analysis. Sub-step 4a: Analyze other activities similar to the proposed project activity In Indonesia, associated gas is considered as a by-product of oil production and is simply flared in order to minimise costs, as well as due to a lack of regulations5. In 2003, Indonesia has been rated by the World Bank6 as the third highest country in terms of quantities flared gas per barrel of oil produced, and the fifth highest country in terms of total annual gas flared. Additionally, in October 2006, World Bank and GGFR7 reported that in Indonesia, out of 76 blocks producing oil and gas, 47 blocks flared gas. As mentioned in the report, BP Migas8 data in 2004 indicated that those 47 onshore and offshore blocks consist of 506 oil fields have flared 358 MMSCFD or equivalent to 3.7 billion m3 gas per year (4.3% of total gas production), and the production from those flaring blocks represent 96% of Indonesias oil production and 82% of its gas production, as summarized in this table below: Total Production Production from

flaring blocks Percent

Oil and condensate (MMBOPD) 1.10 1.03 96 Gas (MMSCFD) 8,302 6,827 82 Turning to LPG supply, to encourage domestic production in 2001 the Indonesian government allowed the private business entities to participate in the development of oil and gas projects and divided the business activities into upstream and downstream9. Every downstream business entities whose activity is gas recovery and processing, is required to obtain a business license from the government to operate. The identification of similar project activities for the common practice analysis below has focused on the geographical country of Indonesia as the host country, on the operational project activities which recover and utilize the associated gas from onshore oilfields and are under the same legal regulatory framework as 5 HWWA Hamburg Report: Gas Flaring Reduction in the Indonesian Oil and Gas Sector Technical and Economic

Potential of Clean Development Mechanism (CDM) projects, Gustya Indriani, 2005. http://www.econstor.eu/dspace/bitstream/10419/32895/1/497849372.pdf 6 Gas Flaring and Venting - A Regulatory Framework and Incentives for Gas Utilization, Franz Gerner, Bent

Svensson, and Sascha Djumena, The World Bank public policy journal, October 2004. http://rru.worldbank.org/documents/publicpolicyjournal/279gerner.pdf 7 The World Bank/GGFR (Global Gas Flaring Reduction): Indonesia Associated Gas Survey Screening and

Economic Analysis Report-25 October 2006. http://siteresources.worldbank.org/INTGGFR/Resources/indonesiaassociatedgassurvey.pdf

8 BP Migas is the regulatory body on Oil and Gas in Indonesia Government 9 Government Law in Oil and Gas No. 22 Year 2001: http://www.pwc.com/en_ID/id/energy-utilities-

mining/assets/law22-2001.pdf

UNFCCC/CCNUCC CDM Executive Board Page 16 mentioned above. Based on the data from Indonesian Ministry of Energy and Mineral Resources10, there are 5 entities have been identified as downstream operational activities. To further identify the similar project activities, the steps in paragraph 47 of Tool for the demonstration and assessment of additionality version 06.0.0 have been applied as follows: Step 1: Calculate applicable output range as +/-50% of the design output or capacity of the proposed project activity. The design output of the proposed project activity is up to 42 ton LPG/day and thus the applicable output range is 21 63 ton LPG/day. Step 2: In the applicable geographical area, identify all plants that deliver the same output or capacity, within the applicable output range calculated in Step 1, as the proposed project activity and have started commercial operation before the start date of the project. Note their number Nall. Registered CDM project activities and projects activities undergoing validation shall not be included in this step The table below has listed all 6 entities operating the downstream actvities in Indonesia, excluding the registered CDM project activity and projects activities undergoing CDM validation. Table B.5-4: The License Holders of LPG plants in Indonesia No. Downstream

Business Entity Location Designed

Capacity Commissioning Year

1. PT. Maruta Bumi Prima

Langkat, North Sumatera

47 ton LPG/day 2001

As shown, all of them have a designed output beyond the applicable output range of 21- 63 ton LPG/day, except the project of PT. Maruta Bumi Prima. Thus, Nall is 1. Step 3: Within plants identified in Step 2, identify those that apply technologies different that the technology applied in the proposed project activity. Note their number Ndiff. In 2003, Pertamina the State-Owned Enterprise became PT Pertamina (Persero)11, although 100% of its shares are still state owned, its role changed from that of a regulator to that of a market participant. Due to this change Pertamina became market oriented12 which affected its business strategy and commercial relationships with their partners in downstream business. PT Maruta Bumi Prima was commissioned and agreed by Pertamina before 2003 and is therefore distinct from proposed project activity in respect to its investment climate. Thus Ndiff = 1. Step 4: Calculate factor F=1-Ndiff/Nall representing the share of plants using technology similar to the technology used in the proposed project activity in all plants that deliver the same output or capacity as the proposed project activity. The proposed project activity is a common practice within a sector in the applicable geographical area if both the following conditions are fulfilled: (a) the factor F is greater than 0.2, and (b) Nall-Ndiff is greater than 3.

10 Annex 5: List of License Holder for Gas Processing in Indonesia Database from Indonesian Ministry of Energy

and Mineral Resources - Directorate General of Oil and Gas 11 Government Regulation No. 31 Year 2003: http://www.anggaran.depkeu.go.id/peraturan/PP%2031%20-

%202003.pdf 12 http://www.pertamina.com/index.php/detail/read/company_history

UNFCCC/CCNUCC CDM Executive Board Page 17 Factor F=1-Ndiff/Nall = 1-1 = 0 and therefore the proposed project activity is not a common practice. Sub-step 4b: Discuss any similar Options that are occurring The above analysis illustrates that the above plants are different and distinct from the propose project activity and it can be concluded that the proposed project activity is not common practice and hence additional. CDM consideration CDM revenue has been a decisive factor in the decision to proceed with the project and the CDM makes the project feasible for the project owners. Efforts to proceed under CDM were taken by GFI, including contacts with several CDM consultants and CDM prior notification to UNFCCC and Indonesian DNA on 25/08/2011.

UNFCCC/CCNUCC CDM Executive Board Page 18 B.6. Emission reductions B.6.1. Explanation of methodological choices Baseline emissions Project activities under this methodology reduce emissions by recovering associated gas and/or gas-lift gas and utilizing the recovered gas. The utilization of the recovered gas displaces the use of other fossil fuel sources. For example:

The use of recovered gas in a processing plant can displace the use of non-associated gas in that processing plant;

In another situation, the recovered gas may be compressed into a natural gas pipeline, thereby displacing the processing of non-associated gas in a gas processing plant at another site.

The exact emission effects are difficult to determine and would require an analysis of the whole fuel supply chain up to the end-users for both the project activity and the baseline scenario. This methodology provides a simplified and conservative calculation of emission reductions, assuming that the use of recovered gas displaces the use of methane the fossil fuel with the lowest direct CO2 emissions. Emissions from processing and transportation of fuels to end-users are neglected for both the project activity and the baseline scenario, as it is assumed that these emissions are similar in their magnitude and level out. Baseline emissions are calculated as follows:

MethaneCOyFRGyFy EFNCVVBE 2,,, ..= (1) Where:

yBE = Baseline emissions in year y, (tCO2e)

yFV , = Volume of total recovered gas measured at point F in Figure A.3.1 in year y, (Nm)

yFRGNCV ,, = Average net calorific value of recovered gas at point F in Figure A.3.1 in year y, (TJ/Nm3)

MethaneCOEF 2 = CO2 emission factor for methane (tCO2/TJ) Project emissions The following sources of project emissions are taken into accounted in line with the methodology:

CO2 emissions due to consumption of fossil fuels for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas up to the point F in Figure A.3.1

CO2 emissions due to the use of electricity for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas up to the point F in Figure A.3.1

Other sources of project emissions such as emissions from leaks, venting and flaring during the recovery, transportation and processing of recovered gas are assumed to be of similar magnitude in the baseline scenario. Project emissions are calculated as follows

yelecCOyfossilfuelCOy PEPEPE ,2,,2 += (2) Where:

yPE = Project emissions in the year y, (tCO2e)

yfossilfuelCOPE ,,2 = CO2 emissions due to consumption of fossil fuels for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas up to the point F in Figure A.3.1 in year y, (tCO2e)


yelecCOPE ,2 = CO2 emissions due to the use of electricity for recovery, pre-treatment, transportation and, if applicable, compression of the recovered gas up to the point F in Figure A.3.1 in year y, (tCO2e)

Project emissions from the consumption of fossil fuels Project emissions PECO2,fossilfuels,y due to the consumption of fossil fuels, including the recovered gas, if applicable for the recovery, pre-treatment, transportation and, if applicable, compression of the recovered gas are calculated applying the latest approved version of the Tool to calculate project or leakage CO2 emissions from fossil fuel combustion where PECO2,fossilfuels,y corresponds to PEFC,j,y in the tool and process j corresponds to all sources of fuel combustion (e.g. a compressor, etc) up to point F in Figure A.3.1 CO2 emissions from fossil fuel combustion in process j are calculated based on the quantity of fuels combusted and the CO2 emission coefficient of those fuels, as follows: ,, ,, , (3) Where: ,, = The CO2 emissions from fossil fuel combustion in process j during the year y (tCO2/yr) ,, = The quantity of fuel type i combusted in process j during the year y (mass or volume

unit/yr); , = The CO2 emission coefficient of fuel type i in year y (tCO2/mass or volume unit) = The fuel types combusted in process j during the year y The CO2 emission coefficient of fuel, ,, can be calculated using one of the following two Options, depending on the availability of data on the fossil fuel type i, as follows: Option A : The CO2 emission coefficient , is calculated based on the chemical composition

of the fossil fuel type i, using the following approach:

If FC,, is measured in a mass unit: COEF, wC,, x 44/12 (4) If FC,, is measured in a volume unit: COEF, wC,, x , x 44/12 (5) Where: COEF, = The CO2 emission coefficient of fuel type i (tCO2/mass or volume

unit); wC,, = The weighted average mass fraction of carbon in fuel type i in year y

(tC/mass unit of the fuel); , = The weighted average density of fuel type i in year y (mass

unit/volume unit of the fuel) i = The fuel types combusted in process j during the year y

Option B : The CO2 emission coefficient , is calculated based on net calorific value and

CO2 emission factor of the fuel type i, as follows: COEF, NCV, x EFCO,, (6) Where: , = The CO2 emission coefficient of fuel type i in year y (tCO2/mass or

volume unit) NCV, = The weighted average net calorific value of the fuel type i in year y

(GJ/mass or volume unit)


EFCO,, = The weighted average CO2 emission factor of fuel type i in year y (tCO2/GJ)

i = The fuel types combusted in process j during the year y Option B is selected due to the availability of data. Project emissions from consumption of electricity Project emissions yelecCOPE ,2 due to the use of electricity for the recovery, pre-treatment, transportation, and, if applicable, compression of the recovered gas are calculated applying the latest approved version of the Tool to calculate baseline, project and/or leakage emissions from electricity consumption where PECO2,elec,y corresponds to PEEC,y in the tool and the electricity consumption sources j in the tool corresponds to all sources of electricity consumption (e.g. a compressor, etc) up to point F in Figure A.3.1. In the generic approach mentioned in the tool, the project emissions from consumption of electricity are calculated based on the quantity of electricity consumed, an emission factor for electricity generation and a factor to account for transmission losses, as follows: PEEC, ECPJ,, x EFEL,, x 1 TDL, (7) Where: PEEC, = Project emissions from electricity consumption in year y (tCO2/yr) ECPJ,, = Quantity of electricity consumed by the project electricity consumption source j in year

y (MWh/yr) EFEL,, = Emission factor for electricity generation for source j in year y (tCO2/MWh) TDL, = Average technical transmission and distribution losses for providing electricity to

source j in year y j = Sources of electricity consumption in the project The determination of the emission factors for electricity generation (EFEL,,) depends on which scenario (A, B or C) applies to the source of electricity consumption: Scenario A: Electricity consumption from the grid. Scenario B: Electricity consumption from (an) off-grid fossil fuel fired captive power plant(s). Scenario C: Electricity consumption from the grid and (a) fossil fuel fired captive power plant(s). Since the project activity is using the electricity from captive power plant, therefore the determination of the emission factors for electricity generation is calculated based on the scenario B, as follows: Option B1: The emission factor for electricity generation is determined based on the CO2 emissions

from fuel combustion and the electricity generation in the captive power plant(s) installed at the site of the electricity consumption source.

In case where none of the captive power plants is a cogeneration plant or where the heat

generation is ignored (subject to the conditions outlined above), the emission factor of the captive power plant(s) is calculated as follows: EFEL,,

FC,. NCV, EFCO,, EG,

(8)

Where: EFEL,, = Emission factor for electricity generation for source j, k or l in year y (tCO2/MWh) FC,. = Quantity of fossil fuel type i fired in the captive power plant n in the time


period t (mass or volume unit) NCV, = Average net calorific value of fossil fuel type i used in the period t (GJ /

mass or volume unit) EFCO,, = Average CO2 emission factor of fossil fuel type i used in the period t

(tCO2 / GJ) EG, = Quantity of electricity generated in captive power plant n in the time

period t(MWh) i = The fossil fuel types fired in captive power plant n in the time period t = Sources of electricity consumption in the project t = Time period for which the emission factor for electricity generation is

determined = Fossil fuel fired captive power plants installed at the site of the electricity consumption source j

Option B2: Using the conservative default values, as follows: A value of 1.3 tCO2/MWh if (a) The electricity consumption source is a project or leakage electricity consumption

source; or (b) The electricity consumption source is a baseline electricity consumption source;and

the electricity consumption of all baseline electricity consumptions sources at the site of the captive power plant(s) is less than the electricity consumption of all project electricity consumption sources at the site of the captive power plant(s).

A value of 0.4 tCO2/MWh if (a) The electricity consumption source is a baseline electricity consumption source; or (b) The electricity consumption source is a project electricity consumption source and the

electricity consumption of all baseline electricity consumptions sources at the site of the captive power plant(s) is greater than the electricity consumption of all project electricity consumption sources at the site of the captive power plant(s).

Option B1 is selected to calculate the emission factor for electricity generation and this selected approach should not be changed during the crediting period. B esides the gas generator set as the main electricity generator system, fossil fuel combustion in the project activity is also envisaged from the emergency diesel generator system located in the project site as the back-up power. For ex-ante estimations the project emissions from the use of diesel in the emergency diesel generator system has been considered zero. The parameters for the calculation of same will be monitored ex-post and the project emissions taken into account as actual. Leakage Leakage emission is calculated as follows:

yECyFCy LELELE ,, += (8) Where: LEy = Leakage emissions in year y (tCO2e) LEFC,y = Leakage emissions due to fossil fuel consumption after point F in Figure A.3.1 in

year y (tCO2e) LEEC,y = Leakage emissions due to electricity consumption after point F in Figure A.3.1 in

year y (tCO2e) Leakage emissions due to fossil fuel consumption Leakage emissions due to fossil fuel consumption in year y (LEFC,y) is calculated applying the latest

UNFCCC/CCNUCC CDM Executive Board Page 22 approved version of the Tool to calculate project or leakage CO2 emissions from fossil fuel combustion where LEFC,y corresponds to PEFC,j,y in the tool and process j corresponds to all sources of fuel combustion (e.g. compressor, decompressor or trailers/trucks/carriers etc) after point F in Figure A.3.1. The same formula for PEFC,j,y for project emissions calculation is used. Leakage emissions due to electricity consumption Leakage emissions due to electricity consumption in year y (LEEC,y) is calculated applying the latest approved version of the Tool to calculate baseline, project and/or leakage emissions from electricity consumption where LEEC,y corresponds to PEEC,y in the tool and the electricity consumption sources j in the tool corresponds to all sources of electricity consumption (e.g. compressor, decompressor or trailers/trucks/carriers etc) after point F in Figure A.3.1. LEEC,, ECLE,, x EFEL,,

x 1 TDL,

Where: ylECLE ,, = Leakage emissions from electricity consumption in year y (tCO2 / yr)

ECLE,, = Quantity of electricity consumed by the project electricity consumption source l in year y (MWh/yr)

EFEL,, = Emission factor for electricity generation for source l in year y (tCO2/MWh) TDL, = Average technical transmission and distribution losses for providing electricity to

source l in year y l = Leakage electricity consumption sources that are supplied with power from captive

power plant(s) installed at one site

Since there is no electricity consumption after point F therefore no leakage emission due to electricity consumption is considered. Emission reductions Emission reductions are calculated as follows:

yyyy LEPEBEER = (10) Where:

yER Emissions reductions in year y (t CO2e)

yBE Emissions in the baseline scenario in year y (tCO2e)

yPE Emissions in the project scenario in year y (tCO2e)

yLE Leakage in year y (t CO2e)

UNFCCC/CCNUCC CDM Executive Board Page 23 B.6.2. Data and parameters fixed ex ante

Data / Parameter EFCO2,Methane

Unit tCO2/TJ

Description CO2 emission factor for methane

Source of data Calculated in line with procedures and data presented in ISO 6976 as referred in the methodology of AM0009 version 05.0.1

Unit Value Source Carbon Content of Methane 12,011 kg/kmol ISO 6976: Table 1 CO2 Emission Factor for Methane

44.01 kg/kmol ISO 6976: Table 1

NCV of Methane (at 250C) 802.60 kJ/mol ISO 6976: Table 3

Value(s) applied 54.834 Choice of data or Measurement methods and procedures

As per AM0009 version 05.0.1, the CO2 emission factor for methane is included in the parameters that are not monitored.

Purpose of data Calculation of baseline emissions Additional comment -

Data / Parameter TDLj,y

Unit -

Description Average technical transmission and distribution losses for providing electricity to source j in year y

Source of data As per Tool to calculate baseline, project and or leakage emissions from electricity consumption, in case of scenario B ,TDLj/k/l,y = 0 as a simplification.

Value(s) applied 0 Choice of data or Measurement methods and procedures

-

Purpose of data Calculation of project emissions Additional comment -

B.6.3. Ex ante calculation of emission reductions As per methodology AM0009 version 05.0.1, the emissions reduction by the project activity is calculated as follows: Based on the feed gas projection, the volume of recovered gas expected is shown as below: Table B.6.3-1: Expected volume of recovered gas


Period y Projected Total Volume of Recovered

Gas (Point F) (Nm3) , 2013 67,898,401 2014 67,898,401 2015 67,898,401 2016 45,265,601 2017 33,383,380 2018 24,613,170 2019 19,803,700 2020 15,543,076 2021 15,543,076 2022 15,543,076

yFRGNCV ,, = 0.0000506 TJ/Nm

3

MethaneCOEF 2 = 54.834 tCO2/TJ Baseline emissions

MethaneCOyFRGyFy EFNCVVBE 2,,, ..= Based on the calculation above, baseline emissions for each specific year are summarized below:

Year Baseline Emissions

(tCO2/year) 2013 188,532 2014 188,532 2015 188,532 2016 125,688 2017 92,695 2018 68,343 2019 54,989 2020 43,158 2021 43,158 2022 43,158

Project Emission

yelecCOyfossilfuelCOy PEPEPE ,2,,2 += Project emissions from the consumption of fossil fuels ,, ,,

,

COEF, NCV, x EFCO,, The quantity of sour gas combusted in process per year are as follows:


Period y Quantity of sour gas combusted (MMSCF/year)

FCsourgas,j,y 2013 673 2014 673 2015 673 2016 449 2017 331 2018 244 2019 196 2020 154 2021 154 2022 154

NCVsourgas,y = 1,139.5 GJ/MMSCF EFCO2,natgas,y = 0.058 tCO2/GJ Based on the formula above, project emissions from fossil fuels combustion for each specific year are summarized below

Period y Project emissions from fossil fuels combustion

(PEFC,j,y) 2013 44,721 2014 44,721 2015 44,721 2016 29,814 2017 21,988 2018 16,211 2019 13,044 2020 10,237 2021 10,237 2022 10,237

Project emissions from consumption of electricity

yECPE , for each specific year is calculated as follows: ( ) += j yjyjELyjPJyEC TDLEFECPE ,,,,,, 1.. Where:

yjTDL , = 0 Emission factor for electricity generation for source j is calculated as follows:

EFEL,, FC,. x NCV, x EFCO,,

EG,

Quantity of electricity generated and consumed by the project electricity consumption source j year y (MWh/year) are as follows:

Period y Quantity of electricity generated and by the


project electricity consumption source ( yjPJEC ,, ) ( tnEG , )

2013 63,360 2014 63,360 2015 63,360 2016 42,240 2017 31,152 2018 22,968 2019 18,480 2020 14,504 2021 14,504 2022 14,504

Quantity of lean gas fired in the captive power plant each year is summarized below:

Period y

Quantity of lean gas fired in the captive power plant (MMSCF/year)( tleangasFC , )

2013 543.6 2014 543.6 2015 543.6 2016 356.4 2017 262.8 2018 193.8 2019 155.9 2020 122.4 2021 122.4 2022 122.4

tleangasNCV , = 994.2 GJ/MMSCF

tleangasCOEF ,2 = 0.058 tCO2/GJ Based on the formula above, emission factor for electricity generation for each year is 0.489 tCO2/MWh; and therefore the project emissions from electricity consumption for each specific year are calculated and summarized as below:

Period y

Project emissions from electricity consumption ( yECPE , )

2013 30,986 2014 30,986 2015 30,986 2016 20,657 2017 15,253 2018 11,232 2019 9,038


2020 7,093 2021 7,093 2022 7,093

Besides the gas generator set as the main electricity generator system, fossil fuel combustion in the project activity is also envisaged from the emergency diesel generator system located in the project site as the back-up power. For ex-ante estimations the project emissions from the use of diesel in the emergency diesel generator system has been considered zero. The parameters for the calculation of same will be monitored ex-post and the project emissions taken into account as actual. Total estimation of project activity emissions

yPE in tCO2/year for each specific year are summarized as table below: Table B.6.3-5: Project Emissions Summary

Year yFCPE , in

tCO2/year yECPE ,

in tCO2/yearyPE

in tCO2/year 2013 44,721 30,986 75,707 2014 44,721 30,986 75,707 2015 44,721 30,986 75,707 2016 29,814 20,657 50,471 2017 21,988 15,253 37,223 2018 16,211 11,232 27,444 2019 13,044 9,038 22,081 2020 10,237 7,093 17,331 2021 10,237 7,093 17,331 2022 10,237 7,093 17,331

Leakage Leakage emissions due to fossil fuel consumption in year y (LEFC,y) is calculated corresponds to PEFC,j,y in the tool and process j corresponds to all sources of fuel after point F in Figure A.3.1. (heat oil heater at gas processing plant).

The quantity of sour gas combusted in process per year is as follows:

Period y Quantity of sour gas combusted after point F

(MMSCF/year) FCsourgas,j,y 2013 132 2014 132 2015 132 2016 88 2017 65 2018 48 2019 39


2020 30 2021 30 2022 30

NCVsourgas,y = 1,139.5 GJ/MMSCF EFCO2,natgas,y = 0.058 tCO2/GJ Based on the formula above, leakage emissions from fossil fuels combustion after point F for each specific year are summarized below:

Period y Leakage emissions from fossil fuels combustion

(LEFC,j,y) 2013 8,769 2014 8,769 2015 8,769 2016 5,846 2017 4,311 2018 3,179 2019 2,558 2020 2,007 2021 2,007 2022 2,007

Emission reductions

yyyy LEPEBEER =

UNFCCC/CCNUCC CDM Executive Board Page 29 B.6.4. Summary of ex ante estimates of emission reductions

Year Baseline emissions (t CO2e)

Project emissions(t CO2e)

Leakage (t CO2e)

Emission reductions (t CO2e)

2013 188,532 75,707 8,769 104,056 2014 188,532 75,707 8,769 104,056 2015 188,532 75,707 8,769 104,056 2016 125,688 50,471 5,846 69,371 2017 92,695 37,223 4,311 51,161 2018 68,343 27,444 3,179 37,720 2019 54,989 22,081 2,558 30,350 2020 43,158 17,331 2,007 23,820 2021 43,158 17,331 2,007 23,820 2022 43,158 17,331 2,007 23,820

Total 1,036,785 416,333 48,222 572,230 Total number of crediting years

10

Annual average over the crediting period 103,679 41,633 4,822 57,223

UNFCCC/CCNUCC CDM Executive Board Page 30 B.7. Monitoring plan B.7.1. Data and parameters to be monitored

Data / Parameter yFV ,

Unit Nm Description Volume of total recovered gas measured at point F in Figure A.3.1 in year ySource of data On-site measurement using Orifice meter Value(s) applied Period y Value

2013 67,898,401 2014 67,898,401 2015 67,898,401 2016 45,265,601 2017 33,383,380 2018 24,613,170 2019 19,803,700 2020 15,543,076 2021 15,543,076 2022 15,543,076

Measurement methods and procedures

Data should be continuosly measured using calibrated orifice meters. Measurements should be taken at the point(s) where recovered gas exits the pre-treatment plant.

Monitoring frequency Continuosly QA/QC procedures Volume of gas should be completely metered with regular calibration of

metering equipment. The measured volume should be converted to the volume at normal temperature and pressure using the temperature and pressure at the time to measurement. The consistency of metered volume of recovered gas at point F in figure A.3.1 will be cross-checked by Barton Chart recorder. This recorder is used as the emergency backup measurement. Calibration will be taken annually or when measuring equipments show deviation from its tolerated fair value.

Purpose of data Calculation of baseline emissions Additional comment -


Data / Parameter yFRGNCV ,,

Unit TJ/Nm3 Description Net calorific value of recovered gas at point F in Figure A.3.1 in year y Source of data On site measurement (Chemical analysis of gas samples taken at point F in

Figure A.3.1 using Gas chromatography) Value(s) applied 0.0000506 Measurement methods and procedures

Measurements should be undertaken in line with national or international fuel standards. Gas samples should regularly be taken at point F in Figure A.3.1 and the molar composition of each gas sample should be determined through chemical analysis following the procedures for QA/QC. Based on the molar composition, the Net Calorific Value on a volumetric basis should be determined for each sample in line with ISO 6976 or an equivalent standard for a combustion reference temperature of 250C and the same metering reference condition used for parameter VF,y. The average NCV during the period y is defined as the arithmetic average of NCVs for the samples taken during the same period.

Monitoring frequency Sampling and compositional analysis and calculation of net calorific value at least monthly

QA/QC procedures Sampling in accordance with ISO 10715 or equivalent standard. Compositional analysis in accordance with ISO 6974 or equivalent standard. Routine maintenance and calibration in accordance with ISO 10723 or equivalent standard. GC calibration gases certified to ISO 6141 or equivalent standard. Annual manufacturer servicing and calibration to ISO17025 or equivalent standard. In case third party laboratories are used, these should as a minimum have ISO17025 accreditation or justify that they can comply with similar quality standards.

Purpose of data Calculation of baseline emissions Additional comment For the purpose of this methodology, the qualifier net is synonymous

with lower and inferior, and the term calorific value is synonymous with heating value. For the purpose of monitoring plan, the Gross calorific value will be resulted from the composition analysis using Gas Chromatography and Net calorific value shall be calculated from data of gross calorific value by multiplying it with 90% (as per guidelines in the 2006 IPCC Volume 20).


Data / Parameter yjsourgasFC ,,

Unit MMSCF/year Description Quantity of sour gas combusted in processes before point F of the figure

A.3.1 (heaters at condensate recovery- amine plant, and RTO) during the year y

Source of data The total result of on site measurement using orifice meters Value(s) applied

Period y Quantity of sour gas combusted (MMSCF/year)

FCsourgas,j,y 2013 673 2014 673 2015 673 2016 449 2017 331 2018 244 2019 196 2020 154 2021 154 2022 154


Volume of sour gas combusted should be completely metered with regular annual calibration of metering equipment.

Monitoring frequency Continuously QA/QC procedures The consistency of metered volume of sour gas combusted in process will

be cross-checked by Barton Chart recorder. This recorder is used as the emergency back-up measurement.

Purpose of data Calculation of project emissions Additional comment -


Data / Parameter ysourgasNCV ,

Unit GJ/MMSCF Description Net calorific value of sour gas combusted in process before point F of the

figure A.3.1 (heaters at condensate recovery- amine plant, and RTO) in year y

Source of data On site measurement (Chemical analysis of gas samples taken at sour gas production after compression using Gas chromatography)

Value(s) applied 1,139.5 Measurement methods and procedures

Measurements should be undertaken in line with national or international fuel standards. Gas samples should regularly be taken at lean gas production before it is used and the molar composition of each gas sample should be determined through chemical analysis following the procedures for QA/QC. Based on the molar composition, the Net Calorific Value on a volumetric basis should be determined for each sample in line with ISO 6976 or an equivalent standard. The average NCV during the period y is defined as the arithmetic average of NCVs for the samples taken during the same period.



Purpose of data Calculation of project emissions Additional comment For the purpose of this methodology, the qualifier net is synonymous

with lower and inferior, and the term calorific value is synonymous with heating value. For the purpose of monitoring plan, the Gross calorific value will be resulted from the composition analysis using Gas Chromatography and Net calorific value shall be calculated from data of gross calorific value by multiplying it with 90% (as per guidelines in the 2006 IPCC Volume 20). The measurement unit will be converted to GJ/MMSCF.


Data / Parameter ynatgasCOEF ,,2

Unit tCO2/GJ Description CO2 emission factor of natural gas used before point F of the figure A.3.1

(compressor, condensate recovery, amine plant and RTO) in the period y Source of data IPCC default values for CO2 emission factor of natural gas at the upper

limit of the uncertainty at a 95% confidence interval as provided in table 1.4 of Chapter1 of Vol. 2(Energy) of the 2006 IPCC Guidelines on National GHG Inventories

Value(s) applied 0.0583


Since there is no CO2 emission factor provided, IPCC Guidelines value should be used.

Monitoring frequency Any future revision of the IPCC Guidelines should be taken into account QA/QC procedures - Purpose of data Calculation of project emissions Additional comment -

Data / Parameter yjPJEC ,,

Unit MWh/year Description Quantity of electricity generated and consumed by the project electricity

consumption j in year y. Source of data On site measurements Value(s) applied

Period y

Quantity of electricity consumed by the project electricity consumption source ( yjPJEC ,, )

2013 63,360 2014 63,360 2015 63,360 2016 42,240 2017 31,152 2018 22,968 2019 18,480 2020 14,504 2021 14,504 2022 14,504


Continuously measured using electricity meter and aggregated at least annually.

Monitoring frequency Continuously QA/QC procedures - Purpose of data Calculation of project emissions Additional comment -


Data / Parameter tleangasgeneratorFC ,,

Unit m3/year Description Quantity of lean gas fired in the captive power plant (gas generator) in the

time period t Source of data Onsite measurements Value(s) applied

Period y

Quantity of lean gas fired in the captive power plant (MMSCF/year)( tleangasFC , )

2013 543.6 2014 543.6 2015 543.6 2016 356.4 2017 262.8 2018 193.8 2019 155.9 2020 122.4 2021 122.4 2022 122.4


Continuously measured using volume meters. The measured unit will be in MMSCF and will be converted into m3.

Monitoring frequency Continuously QA/QC procedures - Purpose of data Calculation of project emissions Additional comment -

Data / Parameter tleangasNCV ,

Unit GJ / MMSCF Description Average net calorific value of lean gas used in the period t for electricity

consumption Source of data On site collection and laboratory measurement. Calculated using 90% of

gross calorific values provided in the laboratory analysis. Value(s) applied 994.2 Measurement methods and procedures

Monthly measurements should be undertaken in line with national or international fuel standards.

Monitoring frequency Monthly QA/QC procedures The laboratories should have ISO17025 accreditation or justify that they

can comply with similar quality standards. Purpose of data Calculation of project emissions Additional comment -


Data / Parameter tleangasCOEF ,,2

Unit t CO2 / GJ Description CO2 emission factor of natural gas used in the period t for electricity

consumption Source of data IPCC default values at the upper or lower limit whatever is more

conservative of the uncertainty at a 95% confidence interval as provided in table 1.4 of Chapter 1 of Vol. 2 (Energy) of the 2006 IPCC Guidelines on National GHG Inventories

Value(s) applied 0.0583 t CO2 / GJ Measurement methods and procedures

Any future revision of the IPCC Guidelines should be taken into account.

Monitoring frequency - QA/QC procedures - Purpose of data Calculation of project emissions Additional comment 2006 IPCC Guidelines on National GHG Inventories is used as there are no

CO2 emission factor is provided from the fuel supplier, or project participant or national default.

Data / Parameter tdieseloilgeneratorFC ,,

Unit m3/year Description Quantity of diesel oil fired in the captive power plant (diesel generator) in

the time period t Source of data Onsite measurements Value(s) applied 0 Measurement methods and procedures

Continuously measured using volume meter.

Monitoring frequency Continuously QA/QC procedures . Purpose of data Calculation of project emissions Additional comment -

Data / Parameter teneratordieseEG ,lg

Unit MWh/year Description Quantity of electricity generated in captive power plant (diesel generator)

in the time period t Source of data Onsite measurements Value(s) applied 0 Measurement methods and procedures

Continuously measured using electricity meter

Monitoring frequency Continously QA/QC procedures - Purpose of data Calculation of project emissions Additional comment -


Data / Parameter tdieseloilNCV ,

Unit GJ / m3 Description Average net calorific value of diesel oil used in the period t for electricity

consumption Source of data On site collection and laboratory measurement or supplied by the supplier

Calculated using 90% of gross calorific values provided in the laboratory analysis.

Value(s) applied 0 Measurement methods and procedures

Monthly measurements should be undertaken in line with national or international fuel standards.

Monitoring frequency Monthly QA/QC procedures - Purpose of data Calculation of project emissions Additional comment -

Data / Parameter tdieseloilCOEF ,,2

Unit t CO2 / GJ Description CO2 emission factor of diesel oil used in the period t for electricity

consumption Source of data IPCC default values at the upper or lower limit whatever is more

conservative of the uncertainty at a 95% confidence interval as provided in table 1.4 of Chapter 1 of Vol. 2 (Energy) of the 2006 IPCC Guidelines on National GHG Inventories

Value(s) applied 0.074 1 Measurement methods and procedures

Any future revision of the IPCC Guidelines should be taken into account.

Monitoring frequency - QA/QC procedures - Purpose of data Calculation of project emissions Additional comment 2006 IPCC Guidelines on National GHG Inventories is used as there are no

CO2 emission factor is provided from the fuel supplier, or project participant or national default.


Data / Parameter ylsourgasFC ,,

Unit MMSCF/year Description Quantity of sour gas combusted in processes after point F of the figure

A.3.1 (heater at LPG Plant) during the year y Source of data On site measurement using orifice meter. Value(s) applied

Period y Quantity of sour gas combusted after point F

(MMSCF/year) FCsourgas,j,y 2013 132 2014 132 2015 132 2016 88 2017 65 2018 48 2019 39 2020 30 2021 30 2022 30


Volume of sour gas combusted should be completely metered with regular annual calibration of metering equipment.

Monitoring frequency Continuously QA/QC procedures The consistency of metered volume of sour gas combusted in process will

be cross-checked by Barton Chart recorder. This recorder is used as the emergency back-up measurement.

Purpose of data Calculation of leakage emissions Additional comment -


Data / Parameter ylsourgasNCV ,,

Unit GJ/MMSCF Description Net calorific value of sour gas combusted in process after point F of the

figure A.3.1 (LPG plant) in year y Source of data On site measurement (Chemical analysis of gas samples taken at sour gas

production after compression using Gas chromatography) Value(s) applied 1,139.5 Measurement methods and procedures

Measurements should be undertaken in line with national or international fuel standards. Gas samples should regularly be taken at lean gas production before it is used and the molar composition of each gas sample should be determined through chemical analysis following the procedures for QA/QC. Based on the molar composition, the Net Calorific Value on a volumetric basis should be determined for each sample in line with ISO 6976 or an equivalent standard. The average NCV during the period y is defined as the arithmetic average of NCVs for the samples taken during the same period.



Purpose of data Calculation of leakage emissions Additional comment For the purpose of this methodology, the qualifier net is synonymous

with lower and inferior, and the term calorific value is synonymous with heating value. For the purpose of monitoring plan, the Gross calorific value will be resulted from the composition analysis using Gas Chromatography and Net calorific value shall be calculated from data of gross calorific value by multiplying it with 90% (as per guidelines in the 2006 IPCC Volume 20). The measurement unit will be converted to GJ/MMSCF.


Data / Parameter ylasnaturaCOEF ,,lg,2

Unit tCO2/GJ Description CO2 emission factor of sour gas used after point F of the figure A.3.1

(heater at LPG plant) in the period y Source of data IPCC default values for CO2 emission factor of natural gas at the upper

limit of the uncertainty at a 95% confidence interval as provided in table 1.4 of Chapter1 of Vol. 2(Energy) of the 2006 IPCC Guidelines on National GHG Inventories

Value(s) applied 0.0583


Since there is no CO2 emission factor provided, IPCC Guidelines value should be used.

Monitoring frequency Any future revision of the IPCC Guidelines should be taken into account QA/QC procedures - Purpose of data Calculation of leakage emissions Additional comment -

B.7.2. Sampling plan As per Standard for sampling and surveys for CDM project activities and programme of activities, the requirements for sampling in the applicable methodology are having precedence. Hence sampling plan for NCV as described in the AM0009 version 05.0.1 is used. B.7.3. Other elements of monitoring plan The operational and managament structure that will be implemented by the project operator in order to monitor emission reductions and any leakage generated by the project activity is decribed in the following figure: CDM operational and management structure

Field Manager - Design, train, establish and manage the system of CDM - Responsible for the implementation and administration of

CDM project activity at the site

Assistant of Field Manager Check the aggregated data Archive the aggregated data in electronic form for at least 2

years after the crediting period Regularly back up the data

Project Supervisor - Aggregate data and report to Assistant of Field Manager - Calibration of equipments (Measure, record, archive)

Project Operators - Daily measurement and recording

(measure, record, archive)

UNFCCC/CCNUCC CDM Executive Board Page 41 Data collection and storage arrangement All data that need to be collected will be measured and recorded at the frequency as per details in B.7.1 by Project operators and then reported to Production Supervisor. Production Supervisor will aggregate those data and then report them to Assistant of Field Manager who will check and archive them in the electronic form, as well as manage the regular data back-up. All data collected as part of monitoring should be archived electronically and be kept at least for 2 years after the end of the last crediting period. 100% of the data should be monitored if not indicated otherwise in the tables above. All measurements should be conducted with calibrated measurement equipment according to national standards. Calibration of metering units The metering units for feed gas must first be calibrated by the Directorate of Metrology and recalibrated once every year. If there is doubt on the accuracy of a metering unit, the recalibration of such metering unit shall be conducted. If the accuracy of any metering unit deviates by more than 2%, the metering unit from the time of the most recent inspection of the metering unit until the time of discovery of the in accuracy shall be adjusted.


SECTION C. Duration and crediting period C.1. Duration of project activity C.1.1. Start date of project activity 11/04/2011, purchase order of the Amine System C.1.2. Expected operational lifetime of project activity 10 years 00 months C.2. Crediting period of project activity C.2.1. Type of crediting period The fixed crediting period is chosen for the project activity C.2.2. Start date of crediting period 01/12/2012 or the date of registration whichever is later C.2.3. Length of crediting period 10 years 00 months


SECTION D. Environmental impacts D.1. Analysis of environmental impacts The Regulation of Environmental Ministry No 11 year 2006 has stipulated that the gas processing plant with a capacity less than 50 MMSCFD is not mandatory to conduct Environmental Impact Analysis (referred to as AMDAL document Analisa Mengenai Dampak Lingkungan). Further, the Regulation of Environmental Ministry No 13 year 2010 stipulated that the project activity which is not required to carry out Environmental Impact, is obliged to carry out Environmental Management Effort and Monitoring Effort. Together these documents are referred to as UKL/UPL report (Upaya Pengelolaan Lingkungan/ Upaya Pemantauan Lingkungan) In compliance to above, PT. Gasuma Federal Indonesia has undertaken an UKL/UPL report for the project activity. This documentation has been obtained its approval by the Oil and Gas Directorate General on 05/11/2008. No other licenses are required to carry out the project activity in regards to environment impact documentation. D.2. Environmental impact assessment Prior to the implementation of the project activity, the associated gas would be flared. The flaring of the associated gas with high content of CO2 and H2S has caused air pollution and endangered living beings at nearby site. The proposed project activity is an environmentally friendly project which reduces the gas flaring activity and enables improvement of the local area where the gas was earlier being flared. It does not require any displacement of local population. The proposed project activity therefore does not cause any adverse social impacts on local population but has rather helped in improving the quality of life.


SECTION E. Local stakeholder consultation E.1. Solicitation of comments from local stakeholders A stakeholder consultation was undertaken on 09/09/2008 to inform the local people of the project owners intention to apply for CDM benefits for the project activity. Identified stakeholders, i.e. local residents, local village representatives, workers on the plant site and their union representatives, local and national government environmental bodies, were invited. In addition, a public notice of the stakeholder meeting was posted in the local newspaper. The stakeholder meeting took place at Sokosari Village Hall, Tuban. The meeting started with introduction to the project by PT. Gasuma Federal Indonesias staff followed by questions from participants. E.2. Summary of comments received No. Question Answer 1. How many employment opportunities PT.

GFI can provide for people from Rahayu Village? How PT. GFI will conduct a fair recruitment process?

Employees will be recruited accordingly. PT GFI was referring to the employment recruitment that was done by JOB PPEJ in Lamongan sub-district. Employment distribution will be done according to the percentage and needs of the company after agreement with the village leader.

2. What will the compensation be if the faulty is done by the company?

Compensation will be given to any faulty that caused by the company. However the company will conduct their working procedure in accordance to the international standard for health, safety and environmental regulation.

3. Please explain the mechanism of building the LPG plant?

A diagram was used to explain the process flow for utilizing the gas from JOB PPEJ in a simple way and also the positive impacts of project activity by reducing the flaring for surrounding villages.

4. Has the environmental impact assessment been done?

UKL/UPL is done with the approval from ministry of environment.

5. What is the Corporate Social Responsibility (CSR) mechanism, how the CSR can be conducted transparently?

CSR activities are given 2.5% of the company profits as part of the companys responsibility to the surrounding villages. CSR will be coordinated with local government to avoid conflict of interest. The priority will be given to the nearest village from the companys location.

6. Is CDM part of AMDAL?

CDM is not part of AMDAL. AMDAL is regulated by Indonesian law, whilst CDM is under the Kyoto Protocol and regulated by UNFCCC.

7.

What is the socio-economic impact from PT. GFI building the LPG plant?

The positive impact from the project is the economic growth for local villagers. The company will recruit from the surrounding villagers for employment both for the skilled and non-skilled labours. The companys employment will increase the income for the villagers who are employed. PT. GFI will try to minimize the negative impact by working in accordance to the international regulations.

UNFCCC/CCNUCC CDM Executive Board Page 45 E.3. Report on consideration of comments received None of the comments received required any actions to be taken.


SECTION F. Approval and authorization The project participants are waiting for the letters of approval from Indonesia and United Kingdom for the project activity. These will be submitted later durin

lpg associated gas

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