Gunung Megang - Final PDD

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

Version 04.1

PROJECT DESIGN DOCUMENT (PDD)

Title of the project activity Gunung Megang Add-on Combined Cycle Project

Version number of the PDD Version 1.3

Completion date of the PDD 16 June 2013 Project participant(s) PT Metaepsi Pejebe Power Generation; and

E.ON Carbon Sourcing GmbH Host Party(ies) Republic of Indonesia Sectoral scope and selected methodology(ies) ACM0007: Conversion from single cycle to

combined cycle power generation Version 6.1.0 Category 1: Energy industries (renewable - / non-renewable sources)

Estimated amount of annual average GHG emission reductions

106,172 tCO2e/yr

SECTION A. Description of project activity A.1. Purpose and general description of project activity >> The proposed project (the "project activity") will convert the single cycle gas-fired Gunung Megang Power Plant into a combined cycle plant. The two existing natural gas based gas turbines have a combined gross installed capacity of 83.18 MW1 and both currently operate in open cycle mode (commenced in April 20072). The purpose of the project activity is to utilise waste heat to generate additional electricity through steam, without upgrade, significant modification or retrofit of the existing open cycle gas turbines. The scope of this project activity includes the installation of two Heat Recovery Steam Generators (HRSGs) which utilize the waste heat from gas turbines to generate steam. Duct burners operating on natural gas fuel will be used to supplement the energy content of the waste heat. The steam will be used to generate electricity via a Steam Turbine with the net total installed capacity of 31.8MW3. The electricity will be sold to the state-owned electricity company (PLN)4 and supplied to the Sumatra national grid through the existing substation built inside the Gunung Megang Power station. The baseline scenario is the same as the existing scenario and is the continuation of the operation of the existing two gas turbines in an open cycle mode, for supply of electricity to the Sumatra grid. Additional electricity would be supplied by the grid, which comprises predominantly power plants fuelled by high carbon intensive fossil fuels such as coal. All of the waste heat utilized for power generation in the project activity would continue to be vented, in absence of the project activity. The project activity will displace electricity that would have been generated and supplied by the Sumatra grid in the baseline. As such, the project activity will reduce the greenhouse gas (GHG) emissions associated with the generation of electricity by the grid, mostly carbon dioxide (CO2). The project activity will generate some incremental GHGs as some additional gas will be used in the project activity. The estimated annual average total GHG emission reductions for the 10-year crediting period are 106,172 tCO2e/yr. The project activity is a clean energy source as it will utilize waste heat to produce energy. The proposed project will contribute to sustainable development in Sumatra in different ways5. The Indonesian Designated National Authority also stipulates in its procedure for issuing Host Country Approval for CDM projects, that the project owner must demonstrate compliance with its established sustainable development criteria. This is demonstrated by the project owner through the formal check method6 and this document has also been submitted to the Indonesian DNA as part of the Host Country LoA process. Social well-being:

The project activity will create temporary employment opportunities during construction and permanent employment opportunities during operation7 for the local people. The project is estimate to generate up to 742,560 man-hours of new employment8 in the 16 months of its construction alone.

1 SD32 (Page 100/296); See Nominal Plant Net Output for Simple Cycle 2 SD55_GE_Commissioning_Closeout (With reference to SD55, the operational warranty is stated to begin 22nd April 2007. At the validation site visit, the DOE approved that this date may be used as the Starting Date of the open cycle plant. The DOE also approved that SD55 is sufficient evidence for this date.) 3 SD3_EPC_latest 4 PT. PLN (Perusahaan Listrik Negara) is the State-owned operator of the transmission and distribution networks in

Indonesia. 5 SD4a_Sustainable_Development_Criteria 6 SD65_Indonesia_Sustainable_Development_Compliance 7 Newly hired highlighted in yellow at SD36_Operation_Organization_chart 8 Manloading Estimate

In addition, the construction of the project will create business opportunities for contractors, manufacturers, transporters and suppliers, etc.

The project will generate much-needed electricity and thus contribute to the social well-being of Sumatra.

Economic well-being: The overall increase in installed capacity of the project activity will partially support the country's target

towards the 67%9 increase in national power generation during 2010 to 2020, and thus contribute to the overall development of the country;

The gains in efficiency of the project activity will contribute to a more efficient use of finite fossil fuel energy resources in Indonesia (namely gas).

Environmental well-being:

The project activity will utilise waste heat to generate electricity, thereby increasing the overall power generation efficiency in the plant. Through this improvement in efficiency, the project activity will reduce GHG emissions when compared to the baseline scenario and will thus contribute to the mitigation of climate change.

The project activity will result in reduction of CO2 emissions and other local pollutants such as NOX and SOX per unit of electricity produced in the plant when compared to other fossil fuel and coal based power generation in the province. Thus the project will contribute to improved air quality.

A.2. Location of project activity A.2.1. Host Party(ies) >> Republic of Indonesia A.2.2. Region/State/Province etc. >> South Sumatra A.2.3. City/Town/Community etc. >> Muara Enim A.2.4. Physical/Geographical location >> The project site is located in Gunung Megang, which is the sub-district of Muara Enim regency. The address is as follows: JI. Raya Palembang - Muara Enim Km. 152 Gunung Megang Muara Enim, South Sumatra, Indonesia. The geographical coordinates of the project site are: 30 30' 26.14" S 1030 48' 01.52" E Project Location Map:

9 SD5_Indonesia_Energy_67%_2010to2020 (or) http://www.theindonesiatoday.com/energy-headlines/7543-indonesia-

electricity-generation-to-increase-67-in-2010-2020-period.htm

A.3. Technologies and/or measures >> The combined cycle power generation technology consists of key equipment such as Gas Turbines, Heat Recovery Steam Generators (HRSGs) and a Steam Turbine (ST). Two units of duct burners operating on natural gas will supplement the waste heat entering the steam turbine. The primary fuel currently utilized for power generation is natural gas supplied by PT. Medco EPI at a capacity of 18 MMSCFD10 , transported using 16" diameter pipeline. The gas fuel is filtered in the scrubber system which has a capacity of 30 MMSCFD before entering into the gas turbine. The project activity will install two HRSGs and one ST to the existing facility to produce additional electricity, by utilising the energy content in the waste heat from the turbine exhaust gas (4680 C) 11, which is currently not used and simply vented. The exhaust flue gas will be passed through the HRSGs to generate steam which will be used in the steam turbine to produce electricity. Use of the otherwise wasted heat in the turbine exhaust gas results in high thermal efficiency compared to other combustion-based generation technologies. The baseline scenario is the same as the scenario existing prior to the implementation of the project activity. Section B.4 identifies the applicable baseline scenario. In the Baseline scenario, electricity is supplied by the grid and additions to the grid. The existing equipment at the project site includes two General Electric LM6000PC gas turbines currently operating in open cycle mode. The two gas turbines currently have a combined gross installed capacity of 83.18 MW12). GE energy, the turbine supplier has also given a capacity guarantee for each gas turbine of 40.575 MW13. This is a guaranteed combined capacity of 81.15 MW. The turbines used in the baseline will not be altered in the project activity. The specifications of the turbines used in the existing facility are presented in the Table below. Table 1: Gas Turbines14 Gas Turbine Unit 1 Unit 2

10 Page 28, Section 3.3.2 of SD33_INCEPTION_REPORT 11 SD3_EPC_latest 12 SD32 (page100/296); See Nominal Plant Net Output for Simple Cycle 13 SD1_Gas_Turbine_Performance_Sheet 14 SD1_Gas_Turbine_Performance_Sheet

Gas Turbine Unit 1 Unit 2 Manufacturer GENERAL ELECTRIC (GE) GENERAL ELECTRIC (GE) Type GE LM6000PC NDWG 10 GT GE LM6000PC NDWG 10 GT Rated Capacity (Guarantee) 40,575 kW 40,575 kW Serial Number 191-537 191-572 Generator Manufacturer MEIDEN MEIDEN Type FRAME 800 LL EK-AFT FRAME 800 LL EK-AFT Serial Number 1 N 7849 R 1 1 N 7848 R 1 Start date of operation April 2007 April 2007 Remaining Lifetime* 14 years 14 years *The choice of remaining lifetime of 14 years has been explained in this section under the heading 'Equipment Lifetime. The project activity will involve the installation and operation of the following equipment: 1. Heat Recovery Steam Generator (HRSG) - 2 units 2. Steam Turbine - 1 unit 3. Cooling system - 1 unit 4. Water Treatment Plant (WTP) and Waste Water Treatment System (WWTP) The specification of key equipment installed for the project activity is presented in Table 2 below. Table 2: Project activity equipment specifications HRSG15 Unit 1 Unit 2 Manufacturer DELTAK DELTAK Type DINO-3328 DINO-3329 Rated Capacity 132.64 t/h 132.64 t/h HP Steam Pressure 66.79 bar 66.79 bar HP Steam Temperature 400.7 C 400.7 C HP Feed water temperature 111.6 C 111.6 C LP Steam Pressure 6.42 bar 6.42 bar LP Steam Temperature 191.2 C 191.2 C LP Feed water temperature 108.8 C 108.8 C Remaining lifetime16 25 years 25 years STEAM TURBINE17 Manufacturer SIEMENS AG Type SST-400 Operational Medium Superheated Water Steam Operation Mode Sliding Inlet Pressure Rated Capacity 132.3 t/h Steam Pressure 64.01 bar Steam Temperature 397.8 C

15 SD8_HRSG_spec_sheet & SD3_EPC_latest 16 SD13_Tool_to_determine_remaining_lifetime_of_equipment_V1 17 SD9_ST_Spec_Sheet

Remaining lifetime18 25 years GENERATOR Apparent Output 42,937 kVA Rated Capacity 34,350 kW Voltage 11 kV (with 5% range) Current 2,253 A Frequency 50 Hz (with 2% range) Speed 1,500 rpm The electricity generated by the project activity will be supplied to the existing substation located in the west side of the power plant. Equipment Lifetime: The earliest Power Purchase Agreement (PPA) signed with PLN has the contract period of 20 years19. The routine maintenance of equipment and the replacement of significant parts extends/ensures the lifespan of the major equipments, such as gas turbines and generators. The project owner has applied default equipment lifetimes as given in Tool to determine the remaining lifetime of the equipment version 1. As per this tool, a default value can be used if the following criteria are met: Criterion 1: The project participants can demonstrate that the equipment has been operated and maintained according to the recommendations of the equipment supplier. Regarding operation of the plant, the plant manager follows a set of standard operating procedures which are designed to meet the equipment suppliers recommendations. SD58_SOP is provided to support this. Regarding maintenance, the project owner has a contract with MTU Maintenance Berlin-Brandenburg, which is an entity authorized by GE, and has a special focus on GE LM series of turbines, which are used by the project owner. SD57_Exclusive Service Agreement MEPPOGEN & MTU.2-1 is provided to support this and demonstrate that the baseline project has been properly maintained. Criterion 2: There are no periodic replacement schedules or scheduled replacement practices specific to the industrial facility, that require early replacement of equipment before the expiry of the technical lifetime; The project owner confirms that there are no periodic replacement schedules or scheduled replacement practices specific to this plant facility, which may require early replacement of equipment before expiry of technical lifetime. This is also evidenced by SD56_Meppo-Gen Plant History Sheet. Criterion 3: The equipment has no design fault or defect and did not have any industrial accident due to which the equipment cannot operate at rated performance levels. The project owner confirms that there are no design faults or defects and that the plant did not have any industrial accidents due to which the equipment cannot operate at rated performance levels. Maintenance records (SD59) for the existing plant confirm this. The technical default lifetime20 of the existing gas turbines (

However, to be conservative, the total lifetime operating hours has been estimated based on the plant load factor of 85% for the combined cycle plant. Assuming that the plant runs at full capacity for 85% of the time, this gives an operational life time of 20 (calculated as 17/0.85) calendar years. This assumption and leads to a higher value of the plant lifetime and overestimates the revenue from this project and hence the calculated rate of return. The existing plant has been operating since April 2007. The combined cycle project is expected to be commissioned in March 2013. The existing plant would have been operating for six calendar years by the time of commissioning of the CCGT project. Hence, the remaining lifetime of the plant at the point of CDM project commissioning would be 20-6 = 14 years. As per the "Tool to determine the remaining lifetime of the equipment", the default lifetime of 25 years21 has been chosen for the economic lifetime of the new steam turbine and boilers. However, given that the project activity depends on the waste heat from the existing gas turbines, the project activity can only continue to operate while the gas turbines continue to operate. As such, the project activity will have an economic life equal to the remaining economic life of the existing gas plant. Therefore, the lifetime of the project activity, and the assessment period, is 14 years. Environmentally sound and safe equipment will be purchased and installed for the project activity. The international equipment suppliers (General Electric (GE), Siemens and Deltak) have a reputation of providing high quality, modern, up-to-date, energy efficient equipment that is proven to be safe for the environment and for operators. The existing system comprises of two sets of Gas Turbine power generator with the combined gross installed capacity of 83.18 MW. Based on historical averages from the last three years of operation, the system consumed around 131,912,025 m3 of natural gas per year and generated 525,248 MWh electricity for supply to the grid. The major GHG emission source considered at the existing site was emission due to natural gas combustion at the gas turbine. The exhaust gas is released to the atmosphere at the exhaust stack.

Figure 2: The flow diagram of existing open cycle power plant system The proposed new system comprises the addition of two sets of HRSG and one steam Turbine power generator with the installed capacity of 31.822 MW. The proposed system will recover the exhaust gas from gas turbine and generate additional electricity thus in increase the overall energy efficiency of the plant. The combined cycle system will consume an estimated 165,953,633 m3 of gas per annum which is higher than existing system. The

21 SD13_Tool_to_determine_remaining_lifetime_of_equipment_V1 22 SD3_EPC_Latest; For Case # 1 under Combined Cycle Add-On

Generator GT

Generator GT

Exhaust Stack

Exhaust Stack

NATIONAL GRID

GHG Emission

GHG Emission Natural Gas

Electricity

Exhaust Gas

Exhaust Gas

131,912,025 m3/yr 525,248 MWh/yr

150 kV

816.54 t/hr 503.99 0C & 1.01 bar

process flow diagram below shows the schematic of the project scenario, as well as details of heat balance23 and energy generation from the proposed project.

Figure 3: The flow diagram of proposed combined cycle power plant system. Monitoring points and parameters monitored are also shown, along with the values applied ex-ante The greenhouse gases involved in the baseline and project scenario are described in section B.3 of this document. The power plant, in project scenario, uses additional gas as compared to baseline scenario. A detailed Monitoring Plan for this project has been described in section B.7. The following table contains some important characteristics of the power plant in the baseline and project scenarios. Table 3: Power plant characteristics Baseline Scenario and Project Scenario S.No Property Baseline Scenario Project Scenario

1 Gross Generation Capacity 83.1824 MW 114.4225 MW

2 Average Annual Allowance for shut-down days (as per PPA)

6.1 days/year26 33 days/year27

3 Actual shut-down days (measured)

25 days/year28 N.A

4 Net Power supplied to grid29 525,248,300 kWh/yr 819,060,000 kWh/yr

5 Total Gas consumption 131,912,02530 cu.m/yr 165,953,63331 cu.m/yr

23 Page 40 & 42, Section 4 of SD33_INCEPTION_REPORT 24 SD32 (Page 100/296); See Nominal Plant Gross Output for Simple cycle (83.178 rounded off to 83.18) 25 SD3_EPC_Latest; Project Gross output = Total Plant Net Output (111.231) + Total Plant Demands (3.186) = 114.417

rounded off to 114.42 26 SD10a_PPA_4May2007, page (61/130 of PDF) 27 SD10c-Draft-amendment-of-PPA-APPENDIX-G1-electricity-price, page G-14, under SO average value 28 See worksheet Historical Shutdown of Revised_SD48_CER_Spreadsheet 29 See worksheet Electricity Generation of revised_SD48_CER_Spreadsheet 30 See worksheet Historical Average of revised_SD48_CER_Spreadsheet

Generator GT

Generator GT

HRSG

HRSG

Generator

ST

NATIONAL GRID

CO2

Exhaust Gas

GHG Emission

Natural Gas Electricity

Steam

Waste Heat

Waste Heat

Monitoring Points

161 t/h HP: 66 bar & 4800C LP: 2.65 bar & 1800C

165,953,633 m3/yr, 1128.9 BTU/SCF

819,060 MWh/yr

816.54 t/hr 503.99 0C & 1.01 bar

816.54 t/hr 503.99 0C & 1.01 bar

161 t/h HP: 66 bar & 4800C LP: 2.65 bar & 1800C

Steam

NCV,i,y, FCi, y EGPJ, y

Supplementary Gas

Supplementary Gas

Exhaust Gas

S.No Property Baseline Scenario Project Scenario 6 Predicted Annual Availability

Factor (as agreed in PPA) 80%32 85%33

7 Plant Load Factor (Total Electricity Generated/Max. Capacity*)

74.8%34 85% (predicted)35

8 Plant Efficiency 38.8%36 42.24%37 *Maximum Capacity is defined as the electricity that would be produced if the plant were to run at full capacity for 8,760 hours in the year. The technology is to be transferred to the host Party by importing the turbine and generator technology and through training provided to the local engineers and the local project team. Additional maintenance and technical support will be provided by the equipment provider during the operation of the plant. 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)

Party A (host) Republic of Indonesia

PT Metaepsi Pejebe Power Generation

No

Party B The Netherlands

E.ON Carbon Sourcing GmbH No

A.5. Public funding of project activity >> There is no public funding provided for the proposed project.

SECTION B. Application of selected approved baseline and monitoring methodology B.1. Reference of methodology >> Methodology Used: The approved consolidated methodology ACM0007: Conversion from single cycle to combined cycle power generation Version 6.1.0 is used for the combined cycle conversion project. Tools used:

Combined tool to identify the baseline scenario and demonstrate additionality, Version 5.0.0

Tool to calculate project or leakage CO2 emissions from fossil fuel combustion, Version 2

Tool to calculate the emission factor for an electricity system, Version 3.0.0

31 See worksheet Data Input - FC Calculation of revised_SD48_CER_Spreadsheet 32 SD10a_PPA_4May2007, page page (61/130 of PDF) 33 SD10b-Draft-amendment-of-PPA-APPENDIX-G1-electricity-price, page G-14 34 SD44_PLF_estimation 35 SD45_PLF_Justification 36 SD32 (Page 100/296); See Nominal Plant Net Efficiency under Simple Cycle 37 SD3 (Page 2/4); See Plant Efficiency under (Case 1)

Tool to determine the remaining lifetime of equipment, Version 01

B.2. Applicability of methodology >> Approved methodology ACM0007 is applicable to the proposed project activity as per the justifications follows:

Methodology Criteria Project Applicability

This methodology applies to project activities that convert one or several grid connected power units at one site from single-cycle to combined-cycle mode.

The project activity will convert a grid connected open cycle power generation facility at one site into a combined cycle facility that adds approximately 31.8 MW of generating capacity.

The unit(s) have an operational history of at least one year with no major retrofit, and at least one unit has an operational history of more than three years with no major retrofit. There is no major retrofit in these time periods.

The unit has an operational history of more than three years (five years) with no major retrofit38 in these time periods. There have been two major maintenance events of note, which did not involve a major retrofit to the units. Details of these maintenance events are provided below this table.

In the case that a unit has less than three years operational history: all project power unit(s) were designed and commissioned for operation in single cycle mode only. This shall be demonstrated by the project participants by providing relevant documents, such as original process diagrams and schemes from the construction of the plant, licenses and/or by an on-site check by the DOE prior to the implementation of the project activity.

The unit began operation in April 200739 and as such has an operational history of more than three years.

During the most recent three years prior to the implementation of the project activity and during the crediting period the project power unit(s) use(d) only the following fuel types: (a). Fossil fuels; and/or (b). Blends of fossil fuels and bio-fuels, where the

bio-fuel is blended to the fossil fuel in a situation that is outside the control of the project participants (such as regulatory requirements to blend biodiesel with diesel or biogas with natural gas).

Note that this methodology does not allow crediting for an increase in the share of bio-fuels.

The project owner has been using only fossil fuel (Natural Gas) for power generation since the open cycle plant was commissioned.

The type(s) of fossil fuels used by the project power unit(s) during the crediting period were also used during the most recent three years prior to the implementation of the project activity, except, where applicable, any auxiliary fuel consumption (e.g. for start-ups) which shall not exceed 3% of the total fuel consumption in the unit(s) (measured on an energy basis).

Natural gas will be the fuel source used in the combined cycle plant and natural gas was also used prior to the project implementation since the open cycle plant started to operate.

38 SD56_MEPPO-GEN PLANT HISTORY SHEET 39 SD55_GE-Commissioning-Closeout

Methodology Criteria Project Applicability Moreover, this methodology is applicable under the condition that the project activity does not increase the lifetime of the existing gas turbine or engine during the crediting period, as determined using the .Tool to determine the remaining lifetime of equipment. (i.e. this methodology is applicable up to the end of the lifetime of existing gas turbine or engine, if shorter than crediting period).

The crediting period chosen is 10 years, without renewal. It has been explained in Section A.4.3 that the remaining lifetime of the equipment is 14 years from the start of CDM activity, so the project activity does not increase the lifetime of the existing plant during the crediting period.

For further clarity, there have been two maintenance events of note:

1. Damage due to Silica content during commissioning in 2007

During the initial operating/commissioning period both gas turbines were contaminated with silica from water being sprayed at the compressor inlet to enhance the output and also in the burner cans to reduce NOx emissions. Due to the contamination, the Turbine 2 was removed and sent to Europe for repairs. During this period a lease engine was utilized at the Site and Turbine 1 continued to remain in service. SD_63 contains the MTU repair report on this repair.

As evidenced by SD_63, this incident was not a major retrofit of the turbine unit(s). 2. Damage to Electric component, 2007

In August 2007, during a unit trip the generator breaker failed to open and the unit motored on the system for approximately 25 minutes before the Power Plant staff were able to disconnect the generator from the Grid. The incident resulted in severe damage to GT1 and to the Sulzer GT / Generator gearbox for which there were no spares available, and to the breaker where there were also no spares available at the time. Temporary repairs were undertaken at the time and permanent repairs were completed when the required damaged items were replaced. The cause of the failure was reported to be the loss of the DC battery supply to the control system.

SD64 contains a report by Sulzer on the repairs performed and is evidence that no major retrofit was done on the turbine(s). In addition, The Combined tool to identify the baseline scenario and demonstrate additionality, Version 5.0.0 lays out the following applicability criteria.

Methodology Criteria Project Applicability Methodologies using this tool are only applicable if the potential alternative scenarios to the proposed project activity available to project participants cannot be implemented in parallel to the proposed project activity.

The only available alternate scenario is to continue to operate the plant in open cycle mode. This scenario cannot be implemented in parallel with the project activity which is to convert the open cycle operation into combined cycle mode.

B.3. Project boundary The spatial extent of the project boundary includes the power plant at the project site and all power plants considered for the calculation of the baseline emissions. A flow diagram of the project boundary, physically delineating the project activity is presented below:

Figure 4: Flow diagram of project boundary

The following table shows which emission sources and gases are included in the project boundary for the purpose of calculating project emissions and baseline emissions:

Generator GT

Generator GT

HRSG

HRSG

GeneratorST

PLN Power Independent Power Producers

NATIONAL

GRID

GHG Emission

GHG Emission: Co2

GHG Emission

Exhaust Gas: Co2

Exhaust Gas: GHG Emission: Co2

Natural Gas

Electricity

Electricity

Electricity

Stea

Stea

Waste Heat

Waste Heat

Project Boundary Monitoring Points

Supplementary Gas

Supplementary Gas

Source GHGs Included? Justification/Explanation

Bas

elin

e sc

enar

io

Grid connected electricity generation

CO2 Yes Significant emission source CH4 No Excluded for simplification. This emission source is

assumed to be very small. N2O No Excluded for simplification. This emission source is

assumed to be very small. On-site fossil fuel combustion to operate the power unit in open cycle mode



assumed to be very small.

Proj

ect s

cena

rio

On-site fossil fuel combustion in the gas turbine to operate in combined cycle mode




On-site fossil fuel consumption to supplement the exhaust heat in operating steam turbine




B.4. Establishment and description of baseline scenario >> Approved consolidated baseline and monitoring methodology ACM0007 - "Conversion from single cycle to combined cycle power generation" version 6.1.0 is used to determine and demonstrate the baseline scenario. The methodology states the approved version of the "Combined tool to identify the baseline scenario and demonstrate additionality" should be used to demonstrate additionality and identify the most plausible baseline scenario. The methodology also states: When the current practice condition (to continue the operation in open cycle) is assessed, the future estimated load factor should reflect the changes due to new conditions in the grid. The future load factor of the open cycle plant in the baseline is unlikely to change due to new conditions in the grid. The baseline plant has a valid PPA for 20 years that specifies the operational parameters. The baseline PLF is based on the technical capacity of the existing open-cycle plant and the cost of generating the electricity by the baseline plant relative to other power plants in the grid. The project activity will increase the efficiency of the power plant by converting to combined cycle technology. As such, the relative cost of electricity generated by the plant will decrease. As a result, PLN has increased the projected availability factor demanded from the plant from 80% to 85% load factor (as the electricity is now slightly cheaper relative to other sources in the grid). This reflects the improved efficiency of the plant and not new conditions in the grid. As such, the increase in the PLF would not apply to the baseline power plant.

Indonesia is facing increased electricity demand and has a current supply shortfall that is forecast to increase in the coming decade4041. Given this scenario, PLN is unlikely (unable) to deviate from its planned power off-take from the various available sources of electricity. There are no significantly new conditions expected in the grid. In 2010, the power generating capacity of the Sumatra grid was over 4.5 GW42. Given such a large base of generating power plants and the forecast supply shortfall, it is unlikely that there will be any changes that will significantly affect the conditions in the grid. As such, the future estimated load factor for the baseline scenario is not likely to be materially affected. The Combined tool to identify the baseline scenario and demonstrate additionality is applied below. Step 1: Identification of alternative scenarios

Identify all alternative scenarios to the proposed CDM project activity(s) which can be the baseline scenario via the following Sub-steps:

1a. Define alternative scenarios to the proposed CDM project activity 1b. Consistency with mandatory applicable laws and regulations Step 1a: Define alternative scenarios to the proposed CDM project activity

In this sub-step, alternatives to the project activity need to be identified. In accordance with the Methodology, the following six possible alternative scenarios/alternatives are identified:

Alternative (1). Proposed project activity undertaken without being registered as a CDM project activity; Alternative (2). Continuation of the current practice ( not implementing the project activity); Alternative (3). If applicable, the proposed project activity undertaken without being registered as a CDM

project activity undertaken at a later point in time (e.g. due to existing regulations, end-of-life of existing equipment, financing aspects).

Alternative (4). Coal fired power plants with the installed capacity equal to proposed project activity Alternative (5). Oil fired power plants with the installed capacity equal to proposed project activity Alternative (6). Renewable power plants with the installed capacity equal to proposed project activity

Step 1a states in the tool "Identify all alternative scenarios that (a) are available to the project participants, (b) cannot be implemented in parallel to the proposed project activity, and (c) provide outputs or services with comparable quality, properties and application areas as the proposed CDM project activity." Alternative (1) This is a feasible and credible alternative and so could be the baseline scenario (but faces investment barriers explained below) Alternative (2) This is a feasible and credible alternative and so could be the baseline scenario Alternative (3) - The existing power plant assets are relatively new (6 years) and have 14 years remaining lifetime. There are no scheduled relevant changes to the existing regulations or financing conditions. As such, Alternative (3) is not applicable. Alternative (4) The investment is being made at an existing natural gas fired power station to extend the capacity by utilizing waste heat. Building a new coal-fired power station represents a completely different kind of investment that could be implemented in parallel to the project activity. However, investment in a coal power plant is not permitted at the site and coal infrastructure is not in place, so this investment is not available to the

40 SD61b_Power_shortage_Indonesia 41 SD61a_Power_shortage_Sumatra 42 SD60 _Sumatra_ Power_Generating _Capacity

project participants. Note that the project owner has an existing gas supply contract43 until 2013 and therefore it is expected that the plant will continue to be operated by natural gas, with a new contract or with the existing contract re-negotiated. A coal fired power plant would also generate more GHG than the proposed project and so would not meet the objectives of the investment or provide outputs of 'comparable' quality. Therefore, Alternative 4 could not be the baseline scenario. Alternative (5) - The investment is being made at an existing natural gas fired power station to extend the capacity by utilizing waste heat. Building a new oil-fired power station represents a completely different kind of investment that could be implemented in parallel to the project activity. However, investment in an oil power plant is not permitted at the site and oil infrastructure is not in place, so this investment is not available to the project participants. Note that the project owner has a gas supply contract44 until 2013 and thereafter it is expected that the plant will continue to be operated by natural gas, with a new contract or re-negotiated existing contract. An oil fired power plant would also generate more GHG than the proposed project and so would not meet the objectives of the investment or provide outputs of 'comparable' quality. Therefore, Alternative 5 could not be the baseline scenario. Alternative (6) The project participants are independent power producers with access to this site and this existing natural gas power plant. Renewable energy resources such as Hydro, Wind, Geothermal and Solar are not adequately obtainable to implement a plant with the rated capacity equal to proposed project activity at this site. Renewable energy power plants also usually generate electricity irregularly and so do not generate electricity suitable for base load supply. Therefore Alternative 6 could not be the baseline scenario. Alternative 1 and Alternative 2 are identified as possible baseline scenarios and are assessed further in Step 1b. A presidential decree45 committed private-sector power producers to supply power under the second phase of the governments fast-track power generation program. The second phase intends to move away from coal and add a second 10,000 MW of capacity by 2013 or 2014 like phase I. Phase one mostly depended on coal based power generation. As such, the continuation of the current scenario based on natural gas fired generation of electricity is in line with national regulations and policies. Step 1b: Consistency with mandatory applicable laws and regulations

Alternatives Explanation Compliance with

country's laws and regulation (Y/N)

(1): Proposed project activity undertaken without being registered as a CDM project activity

This is consistent with prevailing laws and regulations since the project was proposed by the project developer under the current laws and regulations governing the Indonesian power sector. There are several other existing gas fired combined cycle power plants in Indonesia. There is no legal requirement to register projects such as this under the CDM.

Y

(2): Continuation of current practice (to not implementing the project activity)

The current practice is clearly consistent with prevailing laws and regulations. There is no regulation in Indonesia to prevent the continuation of current practice and no regulation that requires the conversion of single cycle power stations to combined cycle.

Y

Alternatives scenarios (1) and (2) are in compliance with mandatory legislation and regulations, taking into consideration the enforcement in Indonesia and national and sectoral policies and regulations. 43 SD15_Gas Contract Signed 44 SD15_Gas Contract Signed 45 SD4_Fast_Track_Programme_2nd_Phase (or) http://www.thejakartaglobe.com/business/indonesia-opens-fast-

track-door-to-private-energy-producers/352537

Step 2. Barrier Analysis Investment barriers The proposed project activity (Alternative 1) does face an Investment Barrier, as demonstrated in Section B.5 below. The continuation of the current scenario (Alternative 2) requires no investment and does not face an investment barrier. Technological barriers There are no major technological barriers that face the proposed project activity (Alternative 1) or the continuation of the current scenario (Alternative 2). Lack of prevailing practice There are no major barriers identified due to prevailing practice as Indonesia has several existing grid connected combined cycle power plants in operation. The above analysis demonstrates that among the identified alternatives, Alternative 1 faces Investment Barriers as explained in section B.5 and Alternative 2, does not face any technical barriers due to implementation. The baseline scenario is thus identified to be the same as the existing scenario, which is the continued operation of the existing Open Cycle Gas Turbine power plant at the existing project site with the existing Plant Load Factor. All of the waste heat utilized for power generation in the project activity would continue to be vented, in absence of the project activity. In the baseline scenario, the OCGT power plant would continue to generate the same amount of electricity per year as in the existing scenario and would continue to provide this electricity to the Sumatra grid. In the baseline scenario, additional electricity would be supplied by existing and new power plants connected to the grid, which comprise predominantly power plants fuelled by high carbon intensive fossil fuels such as coal. As such, the project activity will reduce greenhouse gas emissions associated with the generation of electricity by more carbon intensive fossil-fuel fired power stations connected to the grid. Alternative 1 and Alternative 2 are further assessed using 'Investment Analysis' and the results are presented in Section B.5 below. B.5. Demonstration of additionality >> Prior CDM consideration The early consideration of CDM is demonstrated in accordance with the latest Guidance on the demonstration and assessment of prior consideration of the CDM, version 446. As per the guidelines, the project owner notified in writing the CDM-EB and the Indonesian DNA of the intention to register the project activity with the CDM on 06 May 201147. The Chronology of the project activity is outlined in Table 4 below: Table 4: Project activity events in chronological order

Event Date Supporting Evidence Manufacturing Slot Agreement for Steam turbine with Siemens (Investment Decision Date)

24 November 2010 SD38_Slot_reservation_agreement

Agreement between Meppogen and EON for CDM Project implementation and CER Sale

26 January 2011 Emissions Reductions Purchase Agreement

46 Annex 61 of EB 48 (or)

SD4c_Guidelines_on_The_Demonstration_and_Assessment_of_prior_Consideration_of_the_CDM 47 SD20_Prior consideration note_06May2011

Event Date Supporting Evidence Steam Turbine contract signed 18 March 2011 SD9_ST_Spec_Sheet

CDM Prior Consideration notification issued to UNFCCC Secretariat and Indonesian DNA

6 May 2011 SD20_Prior consideration note_06May2011

Agreement between EON and Biosphere capital for CDM project Consultancy

2 June 2011 Consultancy Contract

EPC contract signed Sep 2011 SD32b_EPC_CONTRACT Construction Start Date Oct 2011 SD32b_EPC_CONTRACT Contract Between Bureau Veritas and EON. 10 Nov 2011 Validation Contract

In compliance with the Tool for the Demonstration and Assessment of Additionality, investment analysis (step 3) has been selected as an appropriate method to demonstrate additionality. Step 1: Identification of Alternatives to the Project Activity Consistent with Current Laws and Regulations Refer above section B.4 Step 2: Barrier Analysis Refer above section B.4 Step 3: Investment Analysis The alternative scenarios remaining after Step 2 are Alternative (1) and Alternative (2). Since one of the alternatives, Alternative (2), is the continuation of current practice that does not require any investment, it is not possible to conduct an investment comparison analysis. Therefore, benchmark analysis is conducted in order to evaluate the financial attractiveness of Alternative (1), the proposed project activity without being registered as a CDM project activity. Equity Internal Rate of Return (E-IRR), or return on equity (ROE) is selected as the most suitable financial indicator, since the investment decisions of the project owner and investors are based on the expected ROE of the project activity. The minimum required ROE for the project must be at least in line with the ROE for similar energy projects in Indonesia for the project to be attractive to investors. Therefore, this analysis compares the E-IRR of the project activity with the benchmark E-IRR required for energy projects in Indonesia. The post-tax E-IRR of the project has been calculated. The appropriate benchmark E-IRR has been selected based on the Guidelines on the assessment of investment analysis (version 5), published as part of the CDM Executive Board's 61st meeting (the Guidelines). According to the Guidelines, paragraph 15: If the benchmark is based on parameters that are standard in the market, the cost of equity should be determined either by: (a) selecting the values provided in Appendix A; or by (b) calculating the cost of equity using best financial practices, based on data sources which can be clearly validated by the DOE, while properly justifying all underlying factors Appendix A of the Guidelines provides conservative default values for the approximate expected return on equity for different project types and host countries. Since the project is in the energy industry it is included in the projects of Group 1 as specified by Appendix A. Thus, given the project is located in Indonesia, the E-IRR benchmark applied for the project in this analysis is 12.5%. This is a post-tax Equity IRR.

Table 5 below presents the main information used in the E-IRR calculation for the project activity. Table 5: Basic parameters for financial evaluation

Parameter Unit Value Data Source

Contracted Capacity: Project MW 110 Draft new PPA48

Contracted Capacity (Baseline)

MW 80 Baseline plant PPA49

Load Factor (AFEA) % 85% PPA50

Net (Additional) Electricity Generation by project

MWh/yr 258,420 Calculation51

Total Investment USD 54,405,543 EPC Proposal, Bank Mandate letter, Management estimation52

Electricity Tariff USD/kWh 0.058 Calculation53

Quantity of Gas Consumption mmBTU/annum 1,137,565 Calculation54

Gas Price (for additional gas consumed in project)

USD/mmBTU 5.255 Price under negotiation

O&M Expenses (additional for the project)

USD/annum 1,960,000 ETSAP study56

Bank Loan USD 45,000,000 Bank mandate letter57

Interest Rate % 8.00% Bank mandate letter

Assessment Period Years 14 Remaining lifetime of the open cycle plant based on default value of Tool to determine remaining

lifetime of equipment

Post-tax IRR % 9.50% Calculation58

Benchmark % 12.50% Guidelines on the assessment of investment analysis (version 5)

Note that the assumed amount of gas consumed in the project scenario is based on the estimated heat rate of the CCGT turbines as specified in the original PPA for the OCGT plant. This PPA specifies estimated heat rates for the gas turbines when run at different Plant Load Factors, including at 80% (the existing and baseline scenario) and at 85% (the proposed project). The PPA thus provides a consistent source of estimates for the gas consumption of the gas turbines for both the baseline and the project scenario. The additional amount of gas consumed by the project as compared to the baseline can therefore be calculated. The gas consumed by the duct 48 SD10c (page G-14) see under CC (MW) 49 SD10a (page 61/130; G-14), see under CC (MW) 50 SD10c (page G-14) under AFp 51 SD_100_Additionality_Spreadsheet; worksheet PLN Tariff 52 SD100_Additionality_Spreadsheet; worksheet Assumptions 53 SD_100_additionality_Spreadsheet; worksheet PLN Tariff 54 SD_100_Additionality_Spreadsheet; worksheet Assumptions 55 SD50_Additional_Gas_Price_MEDCO_MEPPOGEN 56 SD40-gas_fired_power_plant_study (page 4/5); See Table, O&M cost under Costs 57 SD24_Bank_Mandate_Letter 58 SD_100_Additionality_Spreadsheet; See worksheet Cash Flow

burners is added to the additional gas burned in the gas turbines to estimate the total additional gas consumed by the project. This information was available at the time of the investment decision. An estimation of the overall heat rate of the CCGT plant was also later calculated in the EPC documentation (including turbines and duct burner). This was finalised after the investment decision and separately to the PPA. The EPC calculation is considered more technically accurate than the assumptions used in the PPA and so is used in the calculation of emissions reductions. As such, the estimate of gas consumption by the project activity that is used in the calculation of emission reductions is not the same as the estimate used in the financial analysis. The estimate of gas consumption used in the financial analysis is slightly higher than that used in the emission reduction calculations, and thus conservative from an investment analysis and additionality perspective. The post-tax Equity IRR of the project activity without the additional income from CDM is 9.50%, which is below the benchmark ROE of 12.5%. This indicates that the project is not financially viable without CDM assistance and thus indicates that the project is additional. Sensitivity Analysis The key parameters/ assumptions that affect the E-IRR of the project are:

Capital expenditure Electricity tariff Amount of electricity supplied to the grid Gas costs/ price Operational expenses

The impacts on E-IRR due to variations in these key parameters are shown in the Table below.

Table 6: Sensitivity analysis

-10% -5% 0% 5% 10% Threshold

Tariff 1.65% 5.48% 9.50% 13.74% 18.14% 104%

Plant Load factor 21.64% 14.98% 9.50% 2.40% -0.77% 97%

Capex 17.82% 12.50% 9.50% 7.42% 5.84% 95%

O&M expenses 10.60% 10.05% 9.50% 8.95% 8.42% 72%

Gas price 12.82% 11.15% 9.50% 7.88% 6.30% 90%

A range of +/- 10% is applied and threshold values are also calculated:

The analysis is performed with the terms of the draft new PPA (SD10c), as the investment decision was based on these terms It is evident that at the tariff that has been proposed in the draft PPA, the project IRR at 9.50% is below the benchmark. The tariff needs to increase by 4% to reach the benchmark IRR value. Since the tariff is fixed by the PPA for the duration of the PPA, such an increase is not foreseen and therefore the project is additional. In fact, the final PPA offered some time after the investment decision has less favourable terms.

Plant Load factor: To reach the benchmark Equity IRR, the plant load factor must decrease by 3% and reach 82.4%. The calculation of the tariff is complex. It has several different components and is dependent on many variables. Strangely, if the PLF decreases, the net effect is for a slightly higher IRR. If PLN does not take the agreed 85% PLF, PLN will still pay the PP for this amount (though slightly less than the full amount). As such, if for some reason less than 85% is demanded by PLN, the costs of the plant decline while revenue does not hence the IRR increases.This decrease in the PLF is very unlikely given that the draft PPA states a projected Availability Factor of

85%. Therefore PLN will have to pay the project owner for an offtake of 85% or more, even if the actual offtake PLN manages is lower than this projected value of 85%. This makes it uneconomical for PLN to offtake a lower quantity of electricity than 85%. Therefore, the load factor is expected to be 85% or more. Historical records of electricity generation also support the estimation that the load factor for the combined cycle power plant would be at least close to the Availability Factor contracted as per the PPA. Besides, Indonesia is facing increased electricity demand and has a current supply shortfall that is forecast to increase in the coming decade5960. In this scenario, it can be reasonably expected that PLN would offtake its projected electricity quantity of 85% of total contracted capacity or more. Meppogen is contractually obliged to supply this amount and cannot decide to supply less.

Capital expenditure for the project would have to decrease by 5% for the project to be economically attractive and thus not additional. Cost reductions of this magnitude are unlikely given that the cost assumptions are based on current supplier and construction quotations. In fact, there have been several cost increases or variances that were not foreseen and have not been included in the analysis. O&M expenses would need to reduce by 28% for the project to become non-additional. A reduction in O&M cost of this magnitude is extremely unlikely.

The gas price for additional gas used in this project used in the additionality analysis is 5.2 USD/mmBTU. This is the price amendment proposed to the gas supplier MEDCO by the project owner. The project owner has confirmed that this price was rejected by MEDCO as it was deemed to be too low. Negotiations to set the gas price are ongoing, and it is expected that a gas price higher than 5.2 USD/mmBTU will be fixed. In this scenario, the project owners assumption of 5.2 USD/mmBTU for the gas price is very conservative and over-estimates the returns from the project. In the present analysis, the gas price needs to reduce by 10% and reach a value of 4.68 USD/mmBTU for the project to become financially attractive. For the reasons discussed above, a decrease of this magnitude is extremely unlikely.

Step 4: Common practice analysis In addition to the Combined tool to identify the baseline scenario and demonstrate additionality, the methodology ACM0007 version 6.1.0 defines the procedure to undertake common practice analysis. In accordance with the Methodology, similar activities to the project activity are defined as: ...all single cycle and combined cycle power plants that have been an installed capacity within a range of +/- 50% of the project power plant and that are using one of the fossil fuel types used by the project power units. The relevant geographical area is in principle the host country and the relevant geographical area should include preferably ten or more such power plants. The project activity is regarded to be 'common practice' if more than 50% of the assessed power plants operate in combined cycle mode. A list of single and combined gas power plants (within the plant capacity limit between 55MW and 165MW) in Indonesia is presented in the Table below. Table 7: List of single and combined cycle gas-fired power plants in Indonesia with comparable installed capacity

(55 - 165MW) S.No Plant MW Status Type Fuel State

1 ARUN LPG PROJECT 81.25 Operational Gas Turbine Gas Aceh

2 BETARA GAS PLANT 69.9 Operational Gas Turbine Gas Jakarta Raya

3 BEKASI FSW 69.5 Operational Gas Turbine with Steam send out Gas West Java

4 KARAWANG INDAH 83 Operational Gas Turbine with Steam send out Gas West Java

5 CITEUREUP CEMENT WORKS

96 Operational Steam Turbine/Combined Waste Heat West Java

59 SD61b_Power_shortage_Indonesia 60 SD61a_Power_shortage_Sumatra

S.No Plant MW Status Type Fuel State 6 CILACAP 81 Operational Gas Turbine Gas Central Java

7 GRATI 159.58 Operational Steam Turbine/Combined Waste Heat East Java

8 KALIMANTAN MENAMAS 55.5 Operational Gas Turbine with Steam send out Gas East Kalimantan

9 BONTANG LNG PLANT 91.6 Operational Gas Turbine Gas East Kalimantan

10 LHOKSEUMAWE PERTAMINA

104.9 Operational Gas Turbine Gas Aceh

11 MUSI REFINERY 70.2 Operational Gas Turbine Gas South Sumatra

12 PALEMBANG REFINERY 63.3 Operational Gas Turbine Gas South Sumatra

13 BORANG 77.5 Operational Gas Turbine/Combined Gas South Sumatra

14 INDRALAYA 80 Operational Gas Turbine Gas South Sumatra 15 KERAMASAN 159 Operational Gas Turbine Gas South Sumatra

16 BORANG 56.5 Operational Steam Turbine/Combined Waste Heat South Sumatra

17 PALEMBANG PURSI 75.7 Operational Gas Turbine Gas South Sumatra

18 GUNUNG MEGANG 80 Operational Gas Turbine Gas South Sumatra

19 KARAWANG WISMAKARYA 108.4 Operational Gas Turbine with Steam send out Gas West Java

Source: World Electric Power Plants Database from PLATTS Based on the above statistics on power plants in Indonesia, there are 19 power plants that meet the common practice inclusion criteria, of which 4 are combined cycle. "..The project activity is regarded common practice if more than 50% of the assessed power plants operate in combined cycle mode. A power plant is considered to operate in combined cycle mode if any of its units operate in combined cycle mode." Total Number of gas-fired power plants: 54 Total Number of gas-fired power plants between 55MW and 165MW 19 Total Number of combined cycle plant between 55MW and 165 MW 4 Total Proportion of combined cycle plant and single cycle power plants 21% Only 21% of the gas fired power plants of comparable size operating in Indonesia are combined cycle. This is less than the 50% threshold prescribed in the methodology ACM0007 version 6.1.0. Thus, the project activity is not regarded as common practice. Conclusion: Step 3 and Step 4 demonstrated that the project:

is not financially attractive (is less attractive than the alternative) is not common practice

Therefore, the proposed project activity is additional.

B.6. Emission reductions B.6.1. Explanation of methodological choices >> According to ACM007 version 6.1.0, the project activity mainly reduces CO2 emissions through substitution of power generation supplied by the existing generation sources connected to the grid and likely future additions to the grid. The relevant methodological steps are described below: The emission reduction is determined as follows:

yER - Emissions reductions in year y (tCO2) yBE - Baseline emissions in year y (tCO2) yPE - Project emissions in year y (tCO2) yLE - Leakage emissions in year y (tCO2)

a. Baseline Emissions: The baseline scenario is the generation of electricity by the operation of the existing project power unit(s) in single cycle mode as well as by grid-connected power plants. The project will partially displace electricity generated by the project power unit(s) in the baseline scenario. In addition, it is also expected to displace electricity in the grid, as the quantity of electricity generation by the plant is expected to increases as a result of the project activity. However, it is unknown to what extent such an increase is due to the project activity or would have occurred anyway (e.g. due to a change in the electricity demand or availability of other power plants). The calculation of baseline emissions is therefore based on the three cases:

Case 1) The quantity of electricity generated in the project power unit(s), adjusted for changes to efficiency, (EGPJ,adj,y) is lower than or equal to the historic average annual generation level (EGBL,AVR). Baseline emissions are calculated as:

BLCOyadjPJy EFEGBE ,2,, Case 2) The quantity of electricity generated in the project power unit(s), adjusted for changes to efficiency, (EGPJ,adj,y) exceeds the historic average annual generation level (EGBL,AVR) but is lower than or equal to the maximum annual quantity of electricity that the project power unit(s) could have produced prior to the implementation of the project activity (EGMAX). Baseline emissions are calculated as:

);min()( ,,2,,,,,2, ygridBLCOAVRBLyadjPJyBLCOAVRBLy EFEFEGEGEFEGBE Case 3) The quantity of electricity generated in the project power unit(s), adjusted for changes to efficiency, (EGPJ,adj,y) exceeds the maximum annual quantity of electricity that the project power unit(s) could have produced prior to the implementation of the project activity (EGMAX). Baseline emissions are calculated as:

ygridMAXyadjPJ

ygridBLCOAVRBLMAXyBLCOAVRBLy

EFEGEGEFEFEGEGEFEGBE

,,,

,,2,,,2,

)(

);min()(

Where:

BEy - Baseline emissions in year y (tCO2/yr) EGPJ,adj,y - Quantity of electricity supplied by all project power units to the electricity grid in

year y, adjusted for changes to efficiency (MWh/yr)

yyyy LEPEBEER

EGBL,AVR - Average annual quantity of electricity supplied by all project power units to the electricity grid during the defined operational history (MWh/yr)

EGMAX - Maximum annual quantity of electricity that could be generated by all project power units in the baseline scenario (MWh/yr)

EFCO2,BL - Baseline emission factor of all project power units operated in single cycle mode (tCO2/MWh)

EFgrid,y - Emission factor of the electricity grid to which the project power unit is connected (tCO2/MWh)

The project complies with Case 3 requirement as the electricity generated by the combined cycle power plant will exceed the maximum electricity generation capacity of the single cycle plant61. Refer to section B.6.3 and the revised_SD48_CER spreadsheet. In the baseline scenario, the maximum electricity that could have been produced (EGmax) is defined by ACM0007 version 6.1.0 as EGmax = CAPmax . Tmax Referring to this calculation in worksheet Electricity Generation of revised_SD48, EGmax = 677,051 MWh/year. In the project scenario, the plant is expected to operate at a load factor of 85%. Assuming only 85% operational time for the project, this leads to an annual electricity generation of 819,060 MWh/year. Refer to worksheet Electricity Generation of revised_SD48. Since this value is clearly more than maximum possible electricity generation in the baseline scenario. Even if we assume that there are no shutdown hours in the baseline scenario and the plant runs at 100% in the baseline. The electricity generation would be 728,656.8 MWh/year, which is still lower than the expected generation of the plant in CCGT mode. Therefore, case C is selected.

b. Case 3 related Formulas:

The maximum annual quantity of electricity that could be generated by the project power unit(s) in the baseline scenario (EGMAX) is calculated as:

maxmaxMAX TCAPEG

Where: EGMAX - Maximum annual quantity of electricity that could be generated by all project power units in

the baseline scenario (MWh/yr) CAPmax - Maximum gross power generation capacity of the project power unit(s) prior to the

implementation of the project activity (MW) TMAX - Maximum amount of time during a year in which the project power unit(s) could have

operated at full power generation capacity prior to the implementation of the project activity (hours/yr)

If all project power units have three years operational history, and if there was no major retrofit during this period in any of the units, then the maximum annual amount of time that the project power unit(s) could have operated at full load prior to the validation of the project activity is calculated based on below equation.

3760,8

3

1 x

x

MAX

HMRT

61 Operating the 110MW CCGT plant at the planned 85% availability factor is equivalent to 93.5MW, more than the

total possible from the existing 80MW plant

Where: TMAX - Maximum amount of time during a year in which the project power unit(s) could have

operated at full power generation capacity prior to the implementation of the project activity (hours/yr)

HMRx - Average number of hours during which the plant did not operate due to maintenance or repair in year x (hours/yr)

x - Each year during the three years operational history

The average annual amount of electricity supplied to the electricity grid by the project power unit(s) in the three years historical period is calculated according to equation given below. This calculation is based on data from three years operational history there was no major retrofit during this period. This satisfies the condition specified in ACM0007.

3

3

1,

x

x

AVRBL

EGEG

EGBL,AVR - Average annual quantity of electricity supplied by all project power units to the electricity grid during the three year operational history (MWh/yr)

EGx - Quantity of electricity supplied by the project power unit(s) with three years operational history and no retrofit in this period, to the electricity grid in year x (MWh/yr)

x - Each year of the three years operational history

The methodology also states that the total amount of electricity supplied to the electricity grid by all project power units in year y of the crediting period has to be adjusted for the calculation of baseline emissions so that future energy efficiency improvement measures shall not result in emissions reductions. Therefore, the total amount of electricity supplied to the grid (EGPJ,y) shall be conservatively adjusted by applying a discount factor based on the minimum of the monitored efficiencies after the implementation of the project activity, as described in the equations below:

yPJ

yPJyPJyadjPJ EGEG

,

min,,,,,

with

),....,min( ,1,min,, yPJPJyPJ

Where:

EGPJ,adj,y - Quantity of electricity supplied by all project power units to the electricity grid in year y, adjusted for changes to project power plant efficiency (MWh/yr)

EGPJ,y - Total amount of electricity supplied to the electricity grid by the project power units in year y (MWh/yr)

PJ,min,y - Minimum of the yearly average energy efficiency of the project power unit(s) monitored

during the previous years (1 to y) after the implementation of the project activity for year y

PJ,i PJ,y - Average energy efficiency of the project power unit(s) in years 1 to y of the crediting period (refer to PJ,y in the monitoring tables)

c. Estimating the emissions factor for electricity generated in the baseline (EFCO2,BL):

The baseline CO2 emissions factor for the project power unit(s) operated in single cycle mode (EFCO2,BL) is determined based on the historical performance of the units and calculated according to below equation.

min,23

1

3

1,,

,2 CO

xx

x ixixi

BLCO EFEG

NCVFCEF

Where:

EFCO2,BL - CO2 emission factor for electricity generated in single cycle mode in the baseline (tCO2/MWh)

FCi,x - Quantity of fuel type i used by the project power unit(s) in year x (mass or volume unit/yr)

NCVi,x - Net calorific value of the fuel type i used by the project power unit(s) in year x (GJ/mass or volume unit )

EFCO2,min - CO2 emission factor of the least carbon intensive fuel type used by the project power unit(s) during the three years operational history (tCO2/GJ)

EGx - Quantity of electricity supplied by the project power unit(s) with three years operational history and no retrofit in this period, to the electricity grid in year x (MWh/yr)

d. Determine the emissions factor for the grid electricity system (EFgrid,y): The Grid Emission Factor used in the calculation is the Combined Margin CO2 emission factor for grid connected power generation in year y. The calculation was done by Badan Pengkajian dan Penerapan Teknologi (BPPT), which was then approved by the Directorate General of Electricity and Energy Utilization (DJLPE)62. The fuel consumption data for Independent Power Producers (IPP) is calculated from the generated electricity and fuel types. This is due to the unavailability of fuel consumption data for IPPs. The data used for the calculation of the grid emission factor is the most recently available data at the time of submission of the PDD to the DOE. According to Tool to calculate the emission factor for an electricity system version 3.0.0, the following steps were taken. STEP 1. Identify the relevant electricity systems STEP 2. Choose whether to include off-grid power plants in the project electricity system (optional); STEP 3. Select a method to determine the operating margin (OM); STEP 4. Calculate the operating margin emission factor according to the selected method; STEP 5. Calculate the build margin (BM) emission factor; STEP 6. Calculate the combined margin (CM) emission factor. Step 1. Identify the relevant electricity system The Project is connected to the Sumatera grid as delineated by the host Party DNA. Thus the Sumatera grid is identified as the relevant electricity system. Step 2. Choose whether to include off-grid power plants in the project electricity system (optional) For this grid calculation, Option I "Only grid power plants are included in the calculation" is chosen, thus no off-grid power plant is considered in the calculation. Step 3: Select a method to determine the operating margin (OM) For the Sumatera Grid, from 2003-2007, the amount of low-cost/must-run resources connected to the Grid accounted for 20.95%, 17.90%, 17.28%, 19.52% and 21.99% of total Grid generation, respectively. All values are less than 50%, thus method (a) of Simple OM is used to calculate the operating margin emission factor of the 62 DJLPE is the unit within the Ministry of Energy and Mineral Resources which is responsible in electricity and energy

utilization policies, regulations and programs.

Sumatera Grid. See Annex 3 for more details. To calculate the Simple OM emission factor of the Sumatera Grid, the ex-ante option is adopted using the data vintage of a 3-year generation-weighted average, based on the most recent data available at the time of submission of the CDM-PDD to the DOE for validation. Step 4: Calculate the operating margin emission factor according to the selected method Option B is selected because the necessary data for option A, such as data on net electricity generation of each power unit, the average efficiency of each power unit and fuel consumption, is not available for all power plants in Sumatera Grid. Data of fuel consumption for each power plant owned by Independent Power Producers (IPPs) is not publicly available. Thus, Option A cannot be adopted. Therefore, Option B is adopted to calculate the Simple OM emission factor of the Sumatera Grid. Option B - Calculation based on total fuel consumption and electricity generation of the system. Under this option, the Simple OM emission factor is calculated based on the net electricity supplied to the grid by all power plants serving the system, not including low-cost/must-run power plants/units, and based on the fuel type(s) and total fuel consumption of the project electricity system, as follows:

y

iyiCOyiyi

yOMsimplegrid EG

EFNCVFCEF

)( ,,2,,,,

Where: EFgrid,OMsimple,y Simple operating margin CO2 emission factor in year y (tCO2/MWh) FCi,y Amount of fossil fuel type i consumed in the project electricity system in year y

(mass or volume unit) NCVi,y Net calorific value (energy content) of fossil fuel type i in year y (GJ/mass or volume

unit) EFCO2,i, y CO2 emission factor of fossil fuel type i in year y (tCO2/GJ) EGm Net electricity generated and delivered to the grid by all power sources serving the

system, not including low-cost/must-run power plants/units, in year y (MWh) i All fossil fuel types combusted in power sources in the project electricity system in

year y y The relevant year as per the data vintage chosen in Step 3 (2006-2008) For this approach (Simple OM) to calculate the operating margin, the subscript m refers to the power plants/units delivering electricity to the grid, not including low-cost/must-run power plants/units, and including electricity imports to the grid. Electricity imports should be treated as one power plant m. Step 5: Calculate the build margin (BM) emission factor In terms of vintage of date, Option 1 is chosen: build margin emission factor is calculated ex ante based on the most recent information available on units already built for sample group m at the time of CDM-PDD submission to the DOE for validation. Capacity additions from retrofits of power plants are not included in the calculation of the build margin emission factor. The sample group of power units m used to calculate the build margin is determined as per the following procedure, consistent with the data vintage selected above:

(a) Identified the set of five power units, excluding power units registered as CDM project activities, that started to supply electricity to the grid most recently (SET5-units) and determined their annual electricity generation (AEGSET-5-units, in MWh);

(b) Determined the annual electricity generation of the project electricity system, excluding power units

registered as CDM project activities (AEGtotal, in MWh). Identified the set of power units, excluding power units registered as CDM project activities, that started to supply electricity to the grid most recently and that comprise 20% of AEGtotal (if 20% falls on part of the generation of a unit, the generation

of that unit is fully included in the calculation) (SET20%) and determined their annual electricity generation (AEGSET-20%, in MWh);

(c) From SET5-units and SET20% selected the set of power units that comprises the larger annual electricity

generation (SETsample); Identified the date when the power units in SETsample started to supply electricity to the grid. None of the power units in SETsample started to supply electricity to the grid more than 10 years ago, thus SETsample was used calculate the build margin. Steps (d), (e) and (f) are ignored.

The set of power units described as (b) in the Sumatera Grid comprises the larger annual generation than that of (a), thus the sample group (b) is used for calculating the build margin emission factor for Sumatera Grid. Power plants registered as CDM project activities are excluded from the sample group m. Since no plants in the resulting sample group were built more than 10 years ago steps (d), (e) and (f) are ignored. Also, since the 20% falls on part capacity of a unit, that unit is fully included in the calculation which leads to a 20.2% of the total generation. Details are provided in Annex 3. The build margin emissions factor is the generation-weighted average emission factor (tCO2/MWh) of all power units m during the most recent year y for which power generation data is available, calculated as follows:

mym

mymELym

yBMgrid EG

EFEGEF

,

,,,

,,

Where: EFgrid, BM,y Build margin CO2 emission factor in year y (tCO2/MWh) EGm, y Net quantity of electricity generated and delivered to the grid by power unit m in year

y (MWh) EFEL, m, y CO2 emission factor of power unit m in year y (tCO2/MWh) m Power units included in the build margin y Most recent historical year for which electricity generation data is available The CO2 emission factor of each power unit m (EFEL,m,y) is determined as per the guidance in step 4 (a) for the simple OM, using option A1, using for y the most recent historical year for which electricity generation data is available, and using for m the power units included in the build margin. Step 6. Calculate the combined margin (CM) emission factor The weighted average CM (option A) is used. The combined margin emissions factor is calculated as follows:

BMyBMgridOMyOMgridyCMgrid wEFwEFEF ,,,,,,

Where: EFgrid, BM, y Build margin CO2 emission factor in year y (tCO2/MWh) EFgrid, OM, y Operating margin CO2 emission factor in year y (tCO2/MWh) WOM Weighting of operating margin emissions factor (%) WBM Weighting of build margin emissions factor (%) The following default values should be used for wOM and wBM for all projects that are not wind and solar: wOM = 0.5 and wBM = 0.5 for the first crediting period , and wOM = 0.25 and wBM = 0.75 for the second and third crediting period, unless otherwise specified in the approved methodology which refers to this tool. Since a fixed crediting period is chosen, we use wOM = 0.5 and wBM = 0.5.

The resulting emission factor for the Sumatra grid is 0.743 tCo2/MWh.

Project Emissions:

Project emissions (PEy) will be determined using the "Tool to calculate project or leakage CO2 emissions from fossil fuel combustion" version 2. PEy is referred to in this tool as PEFC,j,y where j corresponds to the combustion of fossil fuels to operate the project power unit(s) and to supplement the exhaust heat in operating the steam turbine. In this project, both emission sources apply: a. combustion of fossil fuels to operate the project power units b. to supplement the exhaust heat in operating the steam turbine In the following calculations, PEy is often denoted as PEFC,j,y. 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:

yii

xjiyjFC COEFFCPE ,,,,,

yiCOyiyi EFNCVCOEF ,,2,,

Therefore,

yiCOyii

xjiyjFC EFNCVFCPE ,,2,,,,, Where: PEFC,j,y - CO2 emissions from fossil fuel combustion in process j during the year y (tCO2/yr);

FCi,j,y - Quantity of fuel type i combusted in process j during the year y (mass or volume unit/yr)

COEFi,y - CO2 emission coefficient of fuel type i in year y (tCO2/mass or volume unit)

NCVi,y - Net calorific value of the fuel type i in year y (GJ/mass or volume unit) EFCO2,i,y - Weighted average CO2 emission factor of fuel type i in year y (tCO2/GJ) Leakage Emission: The methodology ACM0007 provides the following scenarios where the leakage will occur:

i. Emissions associated with the situation that exhaust heat was already recovered prior to the implementation of the project activity, in which case the diversion of this heat to the project power unit(s) may increase emissions elsewhere; and Conclusion: The waste heat was not recovered prior to the project implementation. Therefore, this scenario is not applicable for this case.

ii. Emissions associated with extraction, production, transportation, distribution and processing of an increased quantity of fossil fuels consumed by the project activity (LEupstream,y). Since the quantity of natural gas consumed has increased in the project, this scenario is applicable. The relevant calculations are shown below.

Leakage emissions are calculated as follows:

yHR,yupstream,y LELELE

Where: LEy - Leakage emissions in year y (tCO2e/yr) LEupstream,y - Leakage emissions associated with the upstream emissions of an increase in fossil fuel use in

the project activity in year y (tCO2e/yr) LEHR,y - Leakage emissions due to a decrease in the amount of heat recovered from exhaust heat for

purposes other than power generation in the project, compared to the most recent year prior to the implementation of the project activity, in year y (tCO2e/yr)

The waste heat was not recovered63 prior to the project implementation. Therefore, LEHR,y is considered as zero. Hence,

yupstream,y LELE

The methodology states that "Where EGPJ,,adj,y is smaller than EGBL,AVR (as illustrated by case (a) in Figure 1), then leakage emissions from this source are equal to zero."

In proposed project activity, the EGPJ,adj,y is bigger than EGBL,AVR and the fuel consumption by the combined cycle power plant will be higher than the open cycle power plant. Therefore, leakage emissions associated with the upstream emissions of an increase in fossil fuel use in the project activity are calculated as follows:

i

,yi,

3

1=x i,xi,

yCO2,LNG,CH4i

CH4upstream,i,yi,yi,yupstream, FC

FC31

1LEGWPEFNCVFC,0maxLEyi

xi

NCV

NCV

Where: LEupstream,y - Leakage emissions associated with the upstream emissions of an increase in fossil fuel

use in the project activity in the year y (tCO2e/yr) FCi,y - Quantity of fuel type i used by the project power unit(s) in year y (mass or volume

unit/yr) NCVi,y - Average net calorific value of the fuel type i used by the project power unit(s) in year y

(GJ/mass or volume unit) EFi,upstream,CH4 - Emission factor for upstream fugitive methane emissions from production, transportation,

distribution of fossil fuel i used by the project power unit(s) in year y (tCH4/GJ) GWPCH4 - Global warming potential of methane valid for the relevant commitment period

(tCO2e/tCH4) LELNG,CO2,y : - Leakage emissions due to fossil fuel combustion/electricity consumption associated with

the liquefaction, transportation, re-gasification and compression of LNG into a natural gas transmission or distribution system in year y (tCO2e/yr)

FCi,x - Quantity of fuel type i used by the project power unit(s) in year x (mass or volume unit/yr)

NCVi,x - Net calorific value of fuel type i used by the project power unit(s) in year x (GJ/mass or volume unit)

x - Each year of the three years operational history

Leakage emissions due to fossil fuel combustion/electricity consumption associated with the liquefaction, transportation, re-gasification and compression of LNG into a natural gas transmission or distribution system (LELNG,CO2,y) are calculated, where applicable, as follows:

LE LNG,CO2,y FCLNG,y NCVLNG,y EFCO2,upstream,LNG (1) 63 SD34_GT(1)_Side_View_1 & SD35_Open_Cycle_Plant_Front_View

Where: LELNG,CO2,y : - Leakage emissions due to fossil fuel combustion/electricity consumption associated

with the liquefaction, transportation, re-gasification and compression of LNG into a natural gas transmission or distribution system in year y (tCO2e/yr)

FCLNG,y : - Quantity of natural gas produced from LNG used by the project power unit(s) in year y (mass or volume unit/yr)

NCVLNG,y - Net calorific value of natural gas produced from LNG used by the project power unit(s) in year y (GJ/mass or volume unit)

EFCO2,upstream,LNG:

- Emission factor for upstream CO2 emissions due to fossil fuel combustion/electricity consumption associated with the liquefaction, transportation, re-gasification and compression of LNG into a natural gas transmission or distribution system (t CO2e/GJ)

The Natural gas supplied by the fuel supplier is in gaseous form through 16" diameter pipeline64. There will be no liquefaction, transportation, re-gasification and compression of LNG into a natural gas required to the proposed project activity. Therefore, this scenario is not applicable for this case and LELNG,CO2,y would be considered as zero.

Hence,

i

,yi,

3

1=x i,xi,

CH4i

CH4upstream,i,yi,yi,yupstream, FC

FC31

1GWPEFNCVFC,0maxLEyi

xi

NCV

NCV

B.6.2. Data and parameters fixed ex ante Data / Parameter EFBM,y Unit tCO2/MWh Description Build Margin Emission factor for Sumatera Grid Source of data Badan Pengkajian dan Penerapan Teknologi (BPPT) and approved by the

Directorate General of Electricity and Energy Utilization (DJLPE) Value(s) applied 0.581

Choice of data or Measurement methods and procedures

Based on latest grid data available at the time of uploading the PDD for validation. Calculated as per the Tool to Calculate the Emission Factor of an Electricity System.

Purpose of data Calculation of the Grid Emissions Factor and thus baseline emissions Additional comment

Data / Parameter: EFOM,y

64 Page 28, Section 3.3.2 of SD33_INCEPTION_REPORT

Data unit: tCO2/MWh Description: Operating Margin Emission factor for Sumatera Grid Source of data used: Badan Pengkajian dan Penerapan Teknologi (BPPT) and approved by the

Directorate General of Electricity and Energy Utilization (DJLPE) Value applied: 0.906 Choice of data or Measurement methods and procedures

Based on latest grid data available at the time of uploading the PDD for validation. Calculated as per the Tool to Calculate the Emission Factor of an Electricity System.

Purpose of data Calculation of the Grid Emissions Factor and thus baseline emissions Additional comment

Data / Parameter: EGX Data unit: MWh/yr Description: Historical net electricity generation by the power plant in open cycle mode Source of data used: Annual operational reports 65 Value applied: 525,248 Choice of data or Measurement methods and procedures

Yearly plant operation report: The last month plant report which has the accumulation of all the 12 months of power generation Year 2008 554,330,500 kWh/yr Year 2009 579,449,200 kWh/yr Year 2010 441,965,200 kWh/yr Average 525,248,300 kWh/yr

Purpose of data Calculation of baseline electricity generation and thus baseline emissions Additional comment The annual reports prepared by the direct measurement done by the plant

operator. Data / Parameter: FCi, X Data unit: m3/yr Description: Historical fuel (Natural Gas) consumption by the power plant in open cycle

mode Source of data used: Annual operational reports 66 Value applied: 131,912,025 Choice of data or Measurement methods and procedures

Yearly plant operation report: The last month plant report which has the accumulation of all the 12 months of fuel consumption

Purpose of data Calculation of baseline gas consumption and thus baseline emissions Additional comment The annual reports prepared by the direct measurement done by the plant

operator. Refer Annex 3 for 3 years historical data Data / Parameter: NCVi,x

65 SD7a, b,& c_Annual_Operational_Report_2008, 2009 & 2010 66 SD7a, b,& c_Annual_Operational_Report_2008, 2009 & 2010

Data unit: GJ/m3 Description: Net calorific value of Natural Gas used in open cycle mode Source of data used: Gas invoices from supplier 67 Value applied: 0.0379 (refer worksheet Historical Data of

revised_SD48_CER_spreadsheet) Choice of data or Measurement methods and procedures

The value used is obtained from monthly gas invoices provided by gas supplier.

Purpose of data Calculation of the emissions associated with gas consumption for baseline (and project and leakage) emissions

Additional comment Data / Parameter: EFCo2 Data unit: tCO2/GJ Description: Emission Factor for the fuel used in open cycle mode Source of data used: IPCC Default Values. Table 2.2 68 of the chapter 2 (Stationary Combustion)

in Volume 2 (Energy) of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Value applied: 0.0561 Choice of data or Measurement methods and procedures

The other sources such as Value from supplier, Measured data and National data are not available. Therefore, IPCC default value has been taken.

Purpose of data Calculation of the emissions associated with gas consumption for baseline emissions

Additional comment Since natural gas is the only fuel used there are no separate tables for EFCO2,min and EFCO2,max as suggested in ACM0007 version 6.1.0

Data / Parameter: CAPMAX Data unit: MW Description: Maximum gross power generation capacity of the project power unit(s) prior

to the implementation of the project activity Source of data used: Maximum Gross Generation Capacity determined by EPC contractor Value applied: 83.18 69 Choice of data or Measurement methods and procedures

This value is obtained from the EPC proposal provided to the project owner before investment decision.

Purpose of data Calculation of baseline emissions Additional comment

Data / Parameter: TMAX

67 SD54_MEDCO-Gas-Invoices 68 http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf (or)

SD29_IPCC_2006_guidelines_V2-Energy_Ch2-Stationary_Combustion 69 SD32 (page 100/296); See Nominal Plant Net Efficiency under Simple Cycle

Data unit: Hours/yr Description: Maximum amount of time during a year in which the project power unit(s)

could Source of data used: have operated at full power generation capacity prior to the imple

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