PROJECT DESIGN DOCUMENT (PDD)

CDM Executive Board Page 1 PROJECT DESIGN DOCUMENT FORM FOR CDM PROJECT ACTIVITIES (F-CDM-PDD) Version 04.1 PROJECT DESIGN DOCUMENT (PDD) Title of the project activity Aksu Wind Farm Project, Turkey Version number of the PDD 1.0 Completion date of the PDD 30/04/2013 Project participant(s) Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A. S. (private entity) Host Party(ies) Turkey Sectoral scope and selected methodology(ies) Scope number : 1 Sectoral scope : Energy industries (renewable - / non-renewable sources) Methodology: ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources - -- Version 13.0.0 Estimated amount of annual average GHG 118,737 tco 2 -eq emission reductions

CDM Executive Board Page 2 SECTION A. Description of project activity A.1. Purpose and general description of project activity Basic Description: Aksu Wind Farm Project, Turkey (Hereafter referred to as The Project ) is a large scale wind farm project located in Yahyalı District, Kayseri Province of Turkey. The Project is owned by Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A. S. (Hereafter referred to as The Project Proponent ), a private entity. Technical Description: The installed capacity of the project is 72 MW, and the project involves installation and operation of 36 wind turbines, each having a rated power output of 2 MW. The turbines will be of Vestas brand, V100-2.0MW model, and IEC IIIA class. The diameter of the area swept by the blades will be 100 meters and the hub height will be 80 meters. The output voltage of each turbine will be 690 VAC, and this will be stepped up to medium voltage at 33.6 kv. This voltage will again be increased by a power transformer to high voltage at 154 kv and the wind farm will be connected to Camlica-I HEPP substation at this 154 kv level as a single group via an overhead transmission line and from this point the energy will be fed to the national grid. The estimated annual net electricity generation of the project will be about 194,003 MWh. This electrical energy will replace electrical energy of the national grid, based mainly on various fossil fuel sources like natural gas and coal. The expected annual emission reduction to be caused by the project will be around 118,737 tonnes of CO 2 e. For a 7-year crediting period the expected emission reductions will be about 825,899 tonnes of CO 2 e. The operation of the project and electricity generation started in 2012 and the expected operational life of the project is 20 years. Description of sources and gases included in the project boundary: Baseline Emission Sources included in the project boundary are the generation mix of the national grid whose CO 2 emissions are displaced due to the project activity. Project Activity Emission Sources included in the project boundary are those sources emitting gases and particulate matters during construction and operation of the project activity. However, these are minor sources with emissions of very small amounts; so their emissions are neglected and they are excluded. Only CO 2 is included as the gas whose emissions and/or emission reductions will be taken into account due to the project activity. 1) The purpose of the project activity: The purpose of the project activity is to generate renewable electrical energy utilising wind as the primary energy source and deliver this energy to the national grid of Turkey. This energy will help supply Turkey s ever-increasing electricity demand through a clean, sustainable, and reliable technology. The project will displace the same amount of electricity that would otherwise be generated by the fossil fired power plants dominating the national grid. Being the first operational wind farm in Kayseri Province, the project will help renewable energy become more widespread in Turkey. 1.a. The scenario existing prior to the start of the implementation of the project activity:

CDM Executive Board Page 3 The scenario existing prior to the start of the implementation of the project activity was no electricity generation since the project is a greenfield project. Without the implementation of the project, the same amount of energy would be generated by other power plants of the national grid. Considering the general fossil fuel domination in the national grid, a natural gas or coal fired thermal power plant on average would generate this energy. This imaginary power plant would also emit greenhouse gases including CO 2 and particulate matters. Since the project will emit no greenhouse gases within its boundary and no leakage is in question, an emission caused by the net electricity generation displaced by the project activity was produced prior to the implementation of the project. 1.b. The project scenario: The project scenario involves implementation of a wind farm utilising wind as the primary energy source to generate electrical energy and delivery of the generated electricity to the national grid. 36 wind turbines, a high voltage overhead transmission line, a switchyard, an administrative and control building and other necessary minor structures will be installed within the proposed project activity. Necessary measures have been and will be taken during both in the constructional and operational phases of the project in order not to cause any harmful impact on environmental, economical and social structure of the region. All the related legislation and regulations are observed. In addition, the project proponent will make contributions to the sustainable development of the region. 1.c. The baseline scenario: The baseline scenario is the same as the scenario existing prior to the start of implementation of the project activity. 2) Greenhouse gas emission reduction mechanism of the proposed project activity: The project activity will reduce greenhouse gas emissions as reference to the baseline scenario taking into account that it is a zero emission project. No greenhouse gas or particulate matter emission will take place within project boundary and no leakage emissions will occur. Hence, a net emission reduction from the baseline emission level to zero level will result with the energy generated by the project that will displace the energy that would otherwise be generated by the fossil fuel fired power plants in the national grid. Although many harmful gases including the greenhouse gases and particulate matters will be avoided by the emission reduction process, only CO 2 will be considered in the emission reduction. 3) The view of the project participants (The Project Proponent) on the contribution of the project activity to sustainable development: The project activity will result in many positive impacts on the sustainable development of the region. Environment: The electricity produced by the project activity will replace the electricity that would otherwise have been produced by the generation mix of the grid that is mainly composed of fossil fuel fired power plants like natural gas and coal. With the replacement of this energy and resultant avoidance of fossil fuel consumption, not only CO 2 emission will be prevented, but the emission of other greenhouse and various harmful gases and particulate matters will also not occur. As a result, the negative impacts of these pollutants will be reduced. During constructional phase of the project activity, roads to the project site area and the power plant itself on the project site area will be built. Mainly some few amount of dust emission will take place

CDM Executive Board Page 4 during the construction. Other emissions are negligible. Maximum effort will be shown to keep this dust emission as low as possible and all the related national regulations will be observed. Most of the project site area is agricultural fields owned by the inhabitants from the surrounding villages. The project developer made a commitment to solve this problem in an optimal way to satisfy the land owners. Real estate easement agreements were made with land owners to lease the lands for the licence period of the power plant, which is 49 years. So, this issue can be assumed as having been mitigated and solved. The land owners will be able to use parts of their lands that are not used by the wind farm structures within technical limits for agricultural purposes. Landscape arrangements will be made to keep the impact on project site area as low as possible as compared to its original form. Social development The jobs that will be created by the project activity will be high quality jobs requiring professional skills and training. Furthermore, the personnel to be employed in the project will be trained on subjects like occupational health and safety, first aid and fire protection. As a result, employment quality will be increased in the region as compared to the baseline in which more ordinary jobs not requiring professional skills and training would be produced, if any. The Project Proponent intends to make a positive contribution to the livelihood of the poor in the region. In this respect, local people and local authorities and representatives were consulted and their related needs and requests were questioned. As a result, the project proponent undertook the construction of a community health centre built in Dikme Village, the nearest settlement to the project site. This community health centre will ease the access to health care services in the region compared to the baseline. Economical and technological development: Economically, the main positive effect will be on quantitative employment and income generation. Local people will be given priority when employing new personnel for the wind farm depending on their qualifications and professional skills. This will cause an increase in employment quantity and income in the region as compared to the baseline scenario. Without the project, no jobs at all or jobs with lower quality with lower incomes would be generated in the baseline scenario. The project activity will be the first operational wind farm in Kayseri Province. Kayseri Province is an industrially developed part of the Central Anatolian Region of Turkey and had been the only private distribution region of Turkey for a long time before the widespread privatization in electricity distributions of Turkey began. Implementation of the project activity will enhance wind power technology especially in local level. Technological improvements, research and development and production of auxiliary equipment related with wind power technology will be enhanced with the implementation of the project activity. A.2. Location of project activity A.2.1. Host Party(ies) The host party is Turkey. A.2.2. Region/State/Province etc. Central Anatolian Region / Kayseri Province / Yahyalı District

CDM Executive Board Page 5 A.2.3. City/Town/Community etc. The project site is about 35 km away from Yahyalı District Centre, near Dikme Village. Other nearby villages are Karaköy, Delialiuşağı and Avlağa. The nearest turbine to the Dikme Village is about 600 meters away. A.2.4. Physical/Geographical location Location of the project is given in the following figure including the maps of the project region and the turbine layout and the table giving the final coordinates of the individual turbines. (a) (b)

CDM Executive Board Page 6 (c) Figure 1. Maps showing the project location and layout of the turbines. (a) Project location in Turkey. (b) Project location in Central Anatolian Region and Kayseri Province. (c) Layout of the turbines near Dikme Village in the project site area. Table 1. Final turbine coordinates of the project Final Turbine Coordinates of Aksu Wind Farm, Turkey UTM ED50 Coordinates, UTM Zone: 36S Turbine Turbine E N Number Number E N T01 723,049 4,210,172 T19 723,249 4,208,636 T02 723,287 4,210,230 T20 723,183 4,209,170 T03 723,532 4,210,248 T21 722,853 4,209,031 T04 724,990 4,210,224 T22 722,485 4,209,313 T05 725,248 4,210,078 T23 722,243 4,209,382 T06 725,482 4,209,884 T24 721,912 4,209,196 T07 725,807 4,210,010 T25 721,685 4,209,327 T08 726,622 4,209,482 T26 721,329 4,209,407 T09 726,387 4,209,676 T27 721,193 4,209,226 T10 726,182 4,209,449 T28 721,028 4,209,071 T11 725,881 4,209,423 T29 720,778 4,209,029 T12 725,596 4,209,393 T30 720,987 4,208,519 T13 725,355 4,209,539 T31 721,276 4,208,567 T14 725,040 4,209,526 T32 721,508 4,208,573 T15 724,733 4,209,433 T33 724,323 4,208,677 T16 724,418 4,209,321 T34 721,968 4,208,471 T17 723,957 4,209,038 T35 722,232 4,208,313

CDM Executive Board Page 7 T18 721,739 4,208,579 T36 724,707 4,210,397 A.3. Technologies and/or measures The project activity involves electricity generation from renewable energy sources utilising wind energy as the primary energy source. Wind power is one of the main renewable energy sources used in the world for electricity generation. Turkey s electricity generation mainly depends on fossil fuel fired power plants. Natural gas and coal are the main fossil fuels used in the power plants. 1 Although the share of power plants using renewable energy sources is increasing in the recent years, most of these are hydro power plants and the wind power plants still constitute a very small percentage of the national installed capacity. 2,3,4 In the absence of the project, the same amount of electricity would be generated by a hypothetical thermal power plant representing the fossil fuel dominated character of the national grid. This power plant would have most probably been a natural gas coal fired plant. This power plant would cause GHG emissions, mainly CO 2 emissions. The project will cause no GHG emissions. Hence, the project will reduce all the emissions that would take place in its absence. The project is a greenfield project, therefore no other project would be developed in its absence. The baseline scenario and the scenario existing prior to the start of the implementation of the project activity is the same and corresponds to a situation in which the same energy would be generated by the national grid causing GHG emissions. In the scope of the project, 36 wind turbines each having a 2 MW output power will be installed along with auxiliary structures including switchyard, administrative and control buildings, etc. The main components of the turbines include blades, hub, nose cone, nacelle, rotor, gearbox, generator, braking and yaw systems, tower, control systems, etc. among many others. Turbine specifications are summarised in the table below: Table 2. Specifications of Vestas V100-2.0 MW wind turbine Component / Specification Explanation / Value Brand Vestas Model V100 2.0 MW Class IEC IIIA Rated Power 2000 kw Number of blades 3 (Horizontal axis) Rotor diameter 100 m Rotor swept area 7,854 m 2 Hub height 80 m Cut-in Wind Speed 3.0 m/s Rated Wind Speed 12.5 m/s Cut-out Wind Speed 20 m/s Recut-in Wind Speed 18 m/s 1 Fuels Consumed In Thermal Power Plants In Turkey By The Electricity Utilities (2006-2011) (http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2011/yakıt46-49/47.xls) 2 TEIAS Installed Capacity Data of Turkey (http://www.teias.gov.tr/yukdagitim/kuruluguc.xls) (Accessed on 22 January 2013) 3 http://www.yegm.gov.tr/yenilenebilir/document/kuruluguc.xls 4 Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021). (http://www.teias.gov.tr/kapasiteprojeksiyonuaralik2012.pdf)

CDM Executive Board Page 8 Load Factor % 37.2 Generator Efficiency % 97 Average Lifetime 20 years The output voltage of each turbine will be 690 VAC, and this will be stepped up to medium voltage at 33.6 kv. The turbines will be collected in two groups each consisting of 18 turbines and having 36 MW capacities. Each group will be connected to a 154/33.6 kv 50-62.5 MVA transformer and the voltage will again be increased to high voltage at 154 kv. The wind farm will then be connected to Camlica-I HEPP substation at this 154 kv level as a single group via a 12 km long overhead transmission line. From this point on the energy will be fed to the national interconnected grid. Regarding the way how the technologies and measures and know-how to be used in the project are transferred to host party (Turkey), it can be said that the development of the project will most likely cause a positive impact on technological innovation and technology transfer in the region. Although main parts of the project including the turbines and the control system have been exported from abroad, many electrical parts including transformers, switchyard equipment, cabling instruments and most of the constructional material have been supplied from domestic sources. Also, construction work which is specific to wind power technology has been performed by a domestic company. Kayseri Province is a special region that has a unique status in the electricity distribution system of Turkey. Up until recently, Kayseri and Vicinity Electricity Turkish Incorporated Company (KCETAS), the company responsible for the electricity distribution of Kayseri Province, had been the only private electricity distribution company of Turkey 5. Kayseri is one of the most developed provinces of Turkey with respect to industry and trade 6. However, there had been no wind farms in Kayseri Province until the commissioning of Aksu Wind Farm, even though the fact that several licenses have been granted to various companies by Energy Market Regulatory Authority (EPDK) 7. Aksu Wind Farm became the first operational wind farm in Kayseri Province. This is also true for surrounding provinces 8. Although wind power technology is not new in Turkey, most of the wind farms are concentrated in Aegean, Marmara and to a lesser extent some parts of Mediterranean Geographical Regions of Turkey. Due to these reasons, it will very likely enhance technological innovation, technology and know-how transfer and technological self-reliance in the region consisting of Kayseri and surrounding provinces. A.4. Parties and project participants The Project Proponent is the only project participant. The project participant is listed in the following table, and the contact information of the project participant is provided in Annex 1. 5 http://www.kcetas.com.tr/?kanal=tarihce 6 http://www.kayserito.org.tr/media/kayseri_ekonomisinin_turkiyedeki_yeri.pdf 7 http://lisans.epdk.org.tr/epvys-web/faces/pages/lisans/elektrikuretim/elektrikuretimozetsorgula.xhtml http://www2.epdk.org.tr/data/index.htm http://www2.epdk.org.tr/data/epdsantral/kayseri.pdf 8 http://www2.epdk.org.tr/data/index.htm

CDM Executive Board Page 9 Table 3. Parties and Project Participants involved in the Project Party involved (host) indicates a host Party Turkey (host) Private and/or public entity(ies) project participants (as applicable) Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A. S. (private entity) Indicate if the Party involved wishes to be considered as project participant (Yes/No) No The Project Proponent, Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A. S., is the owner and developer of the project. The Republic of Turkey is the host country. Turkey ratified the Kyoto Protocol on 28 May 2009 and the protocol entered into force on 26 August 2009. However, Turkey is a party for which Party for which there is a specific COP and/or CMP decision; and although being an Annex I Country, it has no commitments under Kyoto Protocol. National focal point of Turkey for UNFCCC is the Ministry of Environment and Urban Planning. Regional Environmental Centre Country Office Turkey (REC Turkey) acts as the National Focal Point for UNFCCC Article 6 Education, Training and Public Awareness. A.5. Public funding of project activity No public funding from Parties included in Annex 1 or Official Development Assistance (ODA) is involved for the project activity. SECTION B. Application of selected approved baseline and monitoring methodology B.1. Reference of methodology The approved baseline and monitoring methodology applied to the project activity is ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0. Tools referenced in this methodology: 1. Tool for the demonstration and assessment of additionality 2. Combined tool to identify the baseline scenario and demonstrate additionality 3. Tool to calculate project or leakage CO 2 emissions from fossil fuel combustion 4. Tool to calculate the emission factor for an electricity system Only two of these tools, Tool to calculate the emission factor for an electricity system (Version 03.0.0) for baseline emission calculation and Tool for the demonstration and assessment of additionality (Version 07.0.0) for the assessment of additionality are used. Since no project emission or leakage is in question regarding the project activity, Tool to calculate project or leakage CO 2 emissions from fossil fuel combustion is not used. Combined tool to identify the baseline scenario and demonstrate additionality is also not used since it is not applicable to the project according to the scope and rules defined therein.

CDM Executive Board Page 10 B.2. Applicability of methodology The choice of methodology ACM0002 and related tools are justified based on the fact that the proposed project activity meets the relevant applicability conditions of the chosen methodology and tools: The project is a greenfield project. No power plant or a similar facility had been present in the project site when the project activity began. The project is a grid-connected renewable power generation project. The project activity does not involve any capacity addition or any retrofit or replacement of an existing power plant. The project activity is the installation of a wind power plant. There is no project emission or leakage related with the project activity. B.3. Project boundary The project utilises wind as the primary energy source to generate electricity. During normal operation when enough wind is present to generate wind, the project activity draws no energy from the grid to meet its auxiliary electricity consumption need. The project meets its auxiliary electricity consumption need from its own generated electricity. When there is not sufficient wind to generate electricity, the project will draw some electricity from the grid to use for auxiliary electricity consumption. There is a backup power generator using diesel fuel to be used only when power cannot be supplied from the grid due to a connection loss, grid maintenance, or a power outage in the grid. Under only very such rare occasions will the backup power generator operate and produce emissions. These emissions are expected to be very low and can be neglected; so assumed to be zero. Apart from the backup diesel power generator, there is no equipment or machinery related with the project activity that can produce any emissions. Table 4. Emission sources and GHGs included or excluded in the project boundary Baseline scenario Project scenario Source Electricity generation mix of national grid displaced by project activity Activities during constructional and operational phases of the project GHG s Included? Justification/Explanation CO 2 Yes Major GHG emission from the power plants in the fossil-fuel dominated national grid in the absence of the project activity is CO 2. The amount of other gases and pollutants are very low compared to CO 2. So, CO 2 is included in the baseline emission calculation. CH 4 No Although there may be CH 4 or N 2 O emissions from N 2 O No the power plants in the grid during electricity Other No generation in the absence of the project activity, these emissions would be very low and trivial as compared to CO 2. As a result, CH 4 or N 2 O emissions in the baseline emission calculations are neglected and assumed as zero. CO 2 No Under normal conditions, no CO 2, CH 4 or N 2 O CH 4 No emissions will occur apart from normal domestic N 2 O No activities of the personnel like heating and cooking. Other No And those emissions resulting from these domestic activities will be very low to be taken into account in the calculations. So, these are neglected and not

CDM Executive Board Page 11 included. The wind turbines in the project activity are divided into two groups for which there are separate power transformers and metering systems. There are 21 turbines in Group 1, namely Turbines no. 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 19, 20, 21, 22, 23, 33 and 36. There are 15 turbines in Group 2, namely Turbines no. 1, 2, 3, 18, 24, 25, 26, 27, 28, 29, 30, 31, 32, 34 and 35. The flow diagram of the project boundary with its connections to the national grid is shown in the following figure. The monitoring variable used for emission reduction calculations is the net amount of generated electricity measured by two monitoring systems consisting of main and backup electricity meters for each group.

CDM Executive Board Page 12 Figure 2. Schematic diagram showing the flow diagram of the project boundary, its connection to national grid, and emission sources and gases included in the project boundary and monitoring variables.

CDM Executive Board Page 13 B.4. Establishment and description of baseline scenario The selected baseline methodology for the development of PDD is ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0. So, the most plausible baseline scenario is identified in accordance with this methodology. Baseline methodology procedure explained on pages 4 5 of this methodology proposes three alternatives for identification of the baseline scenario. Since the project activity is the installation of a new grid-connected wind power plant with 36 turbines and is not a capacity addition to or the retrofit or replacement for an existing grid-connected renewable power plant, the first alternative is the most suitable one for the project for identification of the baseline scenario; which is explained as follows 9 : If the project activity is the installation of a new grid-connected renewable power plant/unit, the baseline scenario is the following: Electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources, as reflected in the combined margin (CM) calculations described in the Tool to calculate the emission factor for an electricity system. Since the project activity has nothing to do with a capacity addition or the retrofit or replacement of an existing grid-connected renewable power plant/unit(s) at the project site, the other two alternative scenarios and respective step-wise procedures are not applicable. This assumption of baseline scenario can also be justified and supported by data, statistics and studies performed by TEIAS (Turkish Electricity Transmission Corporation). The following two tables summarize the situation of Turkish Electricity Generation sector as at the end of 2011: Table 5. Distribution of Total Installed Capacity of Turkey by Fuel / Energy Source Types as at the end of 2011 2, 4. THE END OF 2011 FUEL TYPES INSTALLED CAPACITY (MW) CONTRIBUTION (%) NUMBER OF POWER PLANTS FUEL-OIL + ASPHALTITE + NAPHTA + DIESEL OIL 1,362.3 2.6 23 IMPORTED COAL + HARD COAL + LIGNITE 12,355.7 23.4 24 NATURAL GAS + LNG 16,004.9 30.2 155 RENEWABLE + WASTE 115.4 0.2 18 MULTI-FUEL SOLID + LIQUID 556.5 1.1 8 MULTI-FUEL LIQUID + N. GAS 3,536.4 6.7 52 GEOTHERMAL 114.2 0.2 7 HYDRAULIC DAMMED 13,529.3 25.6 58 9 ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0, page 4. (http://cdm.unfccc.int/usermanagement/filestorage/dypfi935xbg274nwh6o8cm1kezr0vu)

CDM Executive Board Page 14 HYDRAULIC RUN-OF-RIVER 3,607.7 6.8 251 WIND 1,728.7 3.3 47 TOTAL 52,911.1 100.0 643 Table 6. Distribution of Gross Electricity Generation of Turkey by Fuel / Energy Source Types in 2011 10 THE DISTRIBUTION OF GROSS ELECTRICITY GENERATION BY PRIMARY ENERGY RESOURCES IN TURKEY 2011 PRIMARY ENERGY RESOURCES Energy (GWh) Share (%) COAL Hard coal+imported Coal+Asphaltite 27,347.5 11.92 Lignite 38,870.4 16.94 COAL TOTAL 66,217.9 28.87 LIQUID FUELS Fuel Oil 900.5 0.39 Diesel Oil 3.1 0.00 LPG 0.0 0.00 Naphtha 0.0 0.00 LIQUID TOTAL 903.6 0.39 Natural Gas 104,047.6 45.36 Renewables and Wastes 469.2 0.205 THERMAL TOTAL 171,638.3 74.82 HYDRO 52,338.6 22.82 GEOTHERMAL 694.3 0.30 WIND 4,723.9 2.06 GENERAL TOTAL 229,395.1 100.00 TEIAS publishes annual capacity projection reports to forecast the future possible situation of Turkish Electricity Sector based on current available data. These projections are performed assuming two different scenarios, one with a high demand assumption, and the other with a low demand assumption. The development of total firm energy generation capacity of Turkish grid for a 10 year period (2012 2021) for these two scenarios according to the latest Capacity Projection Report (2012) are as follows: Table 7. Development of Total Firm Generation Capacity by Energy Resource Types 11 (Scenario 1 High Demand) (Operational, with State Owned Power Plants Under Construction and Private Sector Owned Power Plants Under Construction Granted by Licence and Expected to be in Service on Proposed Date) (Projects Granted by Licence with an Indefinite Date of Commissioning Excluded) (a) Generation (GWh) YEARS 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 LİGNITE 34973 34984 44118 48600 52676 56651 56748 57260 57260 57260 57260 HARD COAL + 3738 3738 3857 3857 4829 5801 5801 5801 5801 5801 5801 10 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2011/uretim%20tuketim(22-45)/44.xls 11 Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021), p. 53. (http://www.teias.gov.tr/kapasiteprojeksiyonuaralik2012.pdf)

CDM Executive Board Page 15 ASPHALTİTE IMPORTED COAL 25461 25461 25426 25002 29474 36481 38272 38311 38311 38311 38311 NATURAL GAS 134625 141708 145475 150184 162289 167216 167848 168184 168184 168184 168184 GEOTHERMAL 802 802 912 1212 1402 1402 1402 1402 1402 1402 1402 FUEL OIL 6805 6805 9034 9034 9034 9034 9034 9034 9034 9034 9034 DIESEL OIL 148 148 148 148 148 148 148 148 148 148 148 NUCLEAR 0 0 0 0 0 0 0 0 4200 12600 21000 OTHERS 1408 1408 1408 1408 1408 1408 1408 1408 1408 1408 1408 THERMAL TOTAL 207959 215053 230376 239443 261259 278139 280659 281547 285747 294147 302547 BIOGAS + WASTE 804 945 1111 1166 1196 1196 1196 1196 1196 1196 1196 HYDRAULIC 53317 56661 44940 48717 54932 62536 67210 68946 69386 69386 69386 WIND 5002 5180 5764 6907 7644 7644 7644 7644 7644 7644 7644 TOTAL 267081 277840 282192 296234 325031 349516 356709 359334 363974 372374 380774 (b) Percentage (%) YEARS 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 LİGNITE 13,1 12,6 15,6 16,4 16,2 16,2 15,9 15,9 15,7 15,4 15,0 HARD COAL + ASPHALTİTE 1,4 1,3 1,4 1,3 1,5 1,7 1,6 1,6 1,6 1,6 1,5 IMPORTED COAL 9,5 9,2 9,0 8,4 9,1 10,4 10,7 10,7 10,5 10,3 10,1 NATURAL GAS 50,4 51,0 51,6 50,7 49,9 47,8 47,1 46,8 46,2 45,2 44,2 GEOTHERMAL 0,3 0,3 0,3 0,4 0,4 0,4 0,4 0,4 0,4 0,4 0,4 FUEL OIL 2,5 2,4 3,2 3,0 2,8 2,6 2,5 2,5 2,5 2,4 2,4 DIESEL OIL 0,1 0,1 0,1 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 NUCLEAR 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 1,2 3,4 5,5 OTHERS 0,5 0,5 0,5 0,5 0,4 0,4 0,4 0,4 0,4 0,4 0,4 BIOGAS + WASTE 0,3 0,3 0,4 0,4 0,4 0,3 0,3 0,3 0,3 0,3 0,3 HYDRAULIC 20,0 20,4 15,9 16,4 16,9 17,9 18,8 19,2 19,1 18,6 18,2 WIND 1,9 1,9 2,0 2,3 2,4 2,2 2,1 2,1 2,1 2,1 2,0 TOTAL 100 100 100 100 100 100 100 100 100 100 100 Table 8. Development of Total Firm Generation Capacity by Energy Resource Types 12 (Scenario 2 Low Demand) (Operational, with State Owned Power Plants Under Construction and Private Sector Owned Power Plants Under Construction Granted by Licence and Expected to be in Service on Proposed Date) (Projects Granted by Licence with an Indefinite Date of Commissioning Excluded) (a) Generation (GWh) YEARS 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 LİGNITE 34973 34976 44109 48600 49714 51964 53298 53810 53810 53810 53810 HARD COAL + ASPHALTİTE 3738 3738 3857 3857 4829 5801 5801 5801 5801 5801 5801 IMPORTED COAL 25461 25461 25426 25002 25214 27961 29752 34051 38311 38311 38311 NATURAL GAS 134625 140423 143243 148138 160616 166641 167848 168184 168184 168184 168184 GEOTHERMAL 802 802 912 1057 1247 1402 1402 1402 1402 1402 1402 FUEL OIL 6805 6805 9034 9034 9034 9034 9034 9034 9034 9034 9034 DIESEL OIL 148 148 148 148 148 148 148 148 148 148 148 NUCLEAR 0 0 0 0 0 0 0 0 4200 12600 21000 OTHERS 1408 1408 1408 1408 1408 1408 1408 1408 1408 1408 1408 THERMAL TOTAL 207959 213760 228137 237243 252208 264357 268689 273837 282297 290697 299097 12 Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021), p. 60. (http://www.teias.gov.tr/kapasiteprojeksiyonuaralik2012.pdf)

CDM Executive Board Page 16 BIOGAS + WASTE 804 872 1038 1166 1196 1196 1196 1196 1196 1196 1196 HYDRAULIC 53317 55923 43676 46966 51459 58052 63771 67744 69386 69386 69386 WIND 5002 5108 5602 6462 7288 7644 7644 7644 7644 7644 7644 TOTAL 267081 275663 278453 291837 312151 331249 341300 350421 360524 368924 377324 (b) Percentage (%) YEARS 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 LİGNITE 13,1 12,7 15,8 16,7 15,9 15,7 15,6 15,4 14,9 14,6 14,3 HARD COAL + ASPHALTİTE 1,4 1,4 1,4 1,3 1,5 1,8 1,7 1,7 1,6 1,6 1,5 IMPORTED COAL 9,5 9,2 9,1 8,6 8,1 8,4 8,7 9,7 10,6 10,4 10,2 NATURAL GAS 50,4 50,9 51,4 50,8 51,5 50,3 49,2 48,0 46,7 45,6 44,6 GEOTHERMAL 0,3 0,3 0,3 0,4 0,4 0,4 0,4 0,4 0,4 0,4 0,4 FUEL OIL 2,5 2,5 3,2 3,1 2,9 2,7 2,6 2,6 2,5 2,4 2,4 DIESEL OIL 0,1 0,1 0,1 0,1 0,0 0,0 0,0 0,0 0,0 0,0 0,0 NUCLEAR 0,0 0,0 0,0 0,0 0,0 0,0 0,0 0,0 1,2 3,4 5,6 OTHERS 0,5 0,5 0,5 0,5 0,5 0,4 0,4 0,4 0,4 0,4 0,4 BIOGAS + WASTE 0,3 0,3 0,4 0,4 0,4 0,4 0,4 0,3 0,3 0,3 0,3 HYDRAULIC 20,0 20,3 15,7 16,1 16,5 17,5 18,7 19,3 19,2 18,8 18,4 WIND 1,9 1,9 2,0 2,2 2,3 2,3 2,2 2,2 2,1 2,1 2,0 TOTAL 100 100 100 100 100 100 100 100 100 100 100 As can be seen from the data depicted in the tables, the current thermal dominated nature of Turkish Electricity Generation Sector is not expected to change within the next ten years significantly. This conclusion justifies the assumption that the baseline scenario is the case in which the electricity delivered to the grid by the project activity would have otherwise been generated by the operation of newly added grid-connected power plants and would correspond to the continuation of current energy resource distribution situation of the national grid. Although a special feed-in-tariff and incentives are given to power plants using renewable energy sources according to Law on Utilization of Renewable Energy Resources for the Purpose of Generating Electrical Energy 13 (Law No: 5346, Issuance Date: 18.05.2005), this supportive mechanism does not seem to change the future probable situation of electricity generation sector in a distinguishable way. So, the assumption of baseline scenario is still valid in the presence of the feed-in-tariff and incentives included in this law. B.5. Demonstration of additionality B.5.1. Implementation Timeline of the Project Activity An overview of Implementation timeline of the project activity can be found in the table below: Table 9. Implementation timeline of the project activity Activity Date Initial Issuance of Generation Licence 29/11/2007 EIA not required certificate 03/11/2009 Transfer of majority shares (70 %) to Ayen Enerji A. S. 14/01/2011 13 http://www.enerji.gov.tr/mevzuat/5346/5346_sayili_yenilenebilir_enerji_kaynaklarinin_elektrik_enerjisi_uretimi_amacli_kullani mina_iliskin_kanun.pdf http://www.epdk.gov.tr/documents/elektrik/mevzuat/kanun/elk_kanun_yek_kanun.doc

CDM Executive Board Page 17 Approval of transfer of shares by EMRA (Energy Market Regulatory Authority) 09/02/2011 Submission of Financial Feasibility Report and EIA Report to creditor bank (TSKB=Turkish Industrial Development Bank), both including and providing evidence that the incentive from 07/04/2011 CDM (Gold Standard VER) was seriously considered in the decision to proceed with the project activity. Turbine purchase and service agreement with turbine supplier (Vestas) 02/05/2011 Credit agreement with creditor bank (TSKB=Turkish Industrial Development Bank) 27/05/2011 Local Stakeholder Meeting 16/06/2011 Start of construction works 19/07/2011 First Partial Commissioning (18 Turbines) (Turbines No. 1, 2, 3, 4, 5, 6, 7, 9, 10, 11, 12, 13, 14, 15, 16, 17, 33, 36) 16/03/2012 Second Partial Commissioning (15 Turbines) (Turbines No. 18, 19, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 34, 35) 05/04/2012 Third and the Last Partial Commissioning (3 Turbines) (Turbines No. 8, 20, 21) 09/06/2012 As can be seen from the implementation timeline of the project, the revenues from VER credits had been taken into account before electromechanical equipment order agreement and credit agreement. VER revenues are considered in the financial analysis performed for investment. Financial Feasibility Report submitted to the creditor bank for credit assessment included VER revenues and the creditor bank took VER revenues into account when giving the credit. Environmental Impact Assessment Report also mentioned VER revenues. B.5.2. Assessment and Demonstration of Additionality The selected baseline methodology for the development of PDD, ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0 refers to the latest version of the Tool for the demonstration and assessment of additionality (Version 07.0.0) (referred to as The Tool hereafter in this section) for the demonstration and assessment of the additionality. The methodology procedure of this tool defines a step-wise approach to be applied for the project activity. The application of this step-wise approach to the proposed project activity is as follows: Step 1: Identification of alternatives to the project activity consistent with current laws and regulations Realistic and credible alternatives to the project activity are defined through the following sub-steps as per the Tool: Sub-step 1a: Define alternatives to the project activity: Probable realistic and credible alternatives that may be available to the Project Proponent are assessed in the following alternate scenarios: a) The proposed project activity undertaken without being registered as a CDM (GS VER) project activity This alternative would be realistic and credible if the project proponent had found the project financially feasible as a result of investment analysis. But the investment analysis showed that the project is not

CDM Executive Board Page 18 financially feasible without the incentive coming from the GS VER revenues. So the project is not considered as credible and feasible by the project proponent although it may be realistic without being registered as a CDM (GS VER) project activity. (b) Other realistic and credible alternative scenario(s) to the proposed CDM project activity scenario that deliver outputs services (e.g., cement) or services (e.g. electricity, heat) with comparable quality, properties and application areas, taking into account, where relevant, examples of scenarios identified in the underlying methodology; The project activity is a power plant using renewable energy sources to generate electricity without emitting any greenhouse gases. So, any other realistic and credible alternative scenario to the proposed project activity scenario that delivers services (electricity) with comparable quality would be another power plant utilising another renewable energy source to generate electricity without emitting any greenhouse gases. But, in the project area there are no other available renewable or non-renewable energy sources to be used for electricity generation. Hence, there are no other realistic and credible alternative scenarios to the proposed project activity that delivers electricity with comparable quality. Therefore, this alternative is not realistic or credible. (c) If applicable, continuation of the current situation (no project activity or other alternatives undertaken). The investment decision for the project activity depends on financial feasibility analysis and risk assessment performed by the project proponent. If the financial feasibility analysis and risk assessment had not been positive, the project would not have been realized. Hence, this scenario in which there would be no project activity is a realistic and credible alternative scenario. This scenario is the continuation of the current situation and corresponds to the case in which the same amount of electricity would be generated by the existing national grid which is composed of a generation mix largely depending on fossil fuels. This alternative is the same as baseline scenario in which the same amount of electricity that would be delivered to the national grid by the project activity would have otherwise been generated by the power plants connected to the national grid whose current composition is mainly dependent on fossil fuels. Outcome of Step 1a: As a result, the above alternatives (a) and (c) are identified as realistic alternative scenarios, but only alternative (c) is found to be the credible alternative scenario to the project activity. Sub-step 1b: Consistency with mandatory laws and regulations: Both the above identified alternatives, whether they are realistic and credible or not are in compliance with all mandatory applicable legal and regulatory requirements, among which the following are the most important ones: Table 10. Important mandatory laws and regulations that the project is consistent with (a) Legislation about electricity generation and marketing: Law / Regulation / Communiqué / Protocol Number / Enforcement Date Electricity Market Law 4628 / 03.03.2001 Law on Utilization of Renewable 5346 / 18.05.2005

CDM Executive Board Page 19 Energy Resources for the Purpose of Generating Electrical Energy Energy Efficiency Law 5627 / 02.05.2007 Electricity Market Licence Regulation - / 04.08.2002 Electricity Market Grid Regulation - / 22.01.2003 Electricity Market Distribution Regulation - / 19.02.2003 Regulation on Procedures and Principles as to Giving Renewable Energy Source Certificate - / 04.10.2005 Regulation on Certification and Support of Renewable Energy Sources - / 21.07.2011 Electricity Transmission System Supply Reliability and Quality Regulation - / 10.11.2004 Electrical Installations Project Regulation - / 16.12.2009 Regulation on Technical Evaluation of Licence Applications based on Wind Energy - / 09.11.2008 Competition Regulation as to Licence Applications to Install Generation Facility Based On Wind Energy - / 22.09.2010 Protocol as to Establishment of Permission Procedures about Effects of Wind Energy Power Plant Installation on Communication, - / 27.12.2010 Navigation and Radar Systems Regulation on Domestic Manufacturing of the Equipment Used in Facilities Generating Electrical Energy from Renewable Energy - / 19.06.2011 Sources Regulation on Electrical Energy Demand Forecasts - / 04.04.2006 Electricity Market Balancing and Settlement Regulation Electricity Market Tariffs Regulation Electricity Market Import and Export Regulation - / 25.09.2002 Electricity Market Customer Services Regulation - / 25.09.2002 Electricity Market Eligible Consumer Regulation - / 04.09.2002 Electricity Market Ancillary Services Regulation - / 27.12.2008 Communiqué on Connection to Transmission and Distribution Systems and System Usage in the Electricity Market - / 27.03.2003 Communiqué on Arrangement of Retail Contract in the Electricity - / 31.08.2003 Market Communiqué on Meters to be used in the Electricity Market - / 22.03.2003 Communiqué on Wind and Solar Measurements - / 11.10.2002 Communiqué on Procedures and Principles of Making Financial Settlement in the Electricity Market (b) Legislation about environment, forestry, labour and social security: - / 30.03.2003 Law / Regulation / Communiqué / Protocol Number / Enforcement Date Environmental Law 2872 / 11.08.1983 Forestry Law 6831 / 08.09.1956 Labour Law 4857 / 22.05.2003 Construction Law 3194 / 09.05.1985 Law on Soil Conservation and Land Use 5403 / 19.07.2005 National Parks Law 2873 / 11.08.1983 Cultural and Natural Heritage Preservation Law 2863 / 23.07.1983 Animal Protection Law 5199 / 01.07.2004

CDM Executive Board Page 20 Environmental Impact Assessment Regulation - / 17.07.2008 Regulation on Environmental Planning - / 11.11.2008 Regulation on Permissions and Licences that have to be taken according to Environmental Law - / 29.04.2009 Air Quality Assessment and Management Regulation - / 06.06.2008 Environmental Auditing Regulation - / 22.09.2010 Regulation on Environmental Agents and Environmental Consulting Firms - / 12.11.2010 Regulation on Assessment and Management of Environmental Noise - / 04.06.2010 Regulation on Control of Waste Oils - / 30.07.2008 Regulation on Amendment in the Regulation on Control of Waste Oils - / 30.03.2010 Regulation on diggings that will be done where it is not possible to construct a sewage course - / 19.03.1971 Regulation on Occupational Health and Safety - / 09.12.2003 Noise Regulation - / 23.12.2003 Vibration Regulation - / 23.12.2003 Regulation on Machine Safety - / 05.06.2002 Outcome of Step 1b: All the alternatives to the project whether they are realistic and credible or not are in compliance with all mandatory applicable and regulatory requirements. Step 2: Investment analysis The purpose of investment analysis is to determine whether the proposed project activity is not (a) The most economically or financially attractive; or (b) Economically or financially feasible, without the revenue from the sale of emission reductions. To conduct the investment analysis, Guidelines on the assessment of investment analysis (Version 05.0) (referred to as The Guidelines hereafter in this section) has also been used apart from The Tool. To conduct the investment analysis, stepwise approach of the Tool has been used. Sub-step 2a: Determine appropriate analysis method The Tool offers three alternative methods to conduct the investment analysis: Option I Option II Option III : Simple Cost Analysis : Investment Comparison Analysis : Benchmark Analysis Since the project activity and the alternatives identified in Step 1 generate financial or economic benefits by electricity sales, Option I (Simple Cost Analysis) cannot be applied. To decide between Option II (Investment Comparison Analysis) and Option III (Benchmark Analysis), Paragraph 19 of the Guidance (page 5) has been used. According to this clause, since the alternative to the project activity is the supply of the electricity from the existing grid, Benchmark Analysis (Option III) is considered appropriate.

CDM Executive Board Page 21 Sub-step 2b: Option III. Apply benchmark analysis IRR (Internal Rate of Return) is identified as the most suitable financial/economic indicator for the demonstration and assessment of additionality. Equity IRR is selected as the IRR type to be used in the benchmark analysis. According to the Guidelines, Required/expected returns on equity are appropriate benchmarks for an equity IRR. When applying the benchmark analysis, the parameters that are standard in the market are used, according to the Paragraph 37 of the Tool. Sub-step 2c: Calculation and comparison of financial indicators (only applicable to Options II and III): A) Benchmark Rate Calculation To find the benchmark rate, option (a) of the Paragraph 38 of the Tool is used: 38. Discount rates and benchmarks shall be derived from: (a) Government bond rates, increased by a suitable risk premium to reflect private investment and/or the project type, as substantiated by an independent (financial) expert or documented by official publicly available financial data; The benchmark rate is specified as the expected returns on equity (expected return on the capital asset / cost of equity); and calculated using the Capital Asset Pricing Model (CAPM), as follows: E(R i ) = R f + β i (E(R m ) R f ) where: E(R i ) R f β i R m E(R m ) R f : Expected returns on equity (Cost of Equity) : Risk Free Return Rate in the Market (e.g. government bond yield) : Beta Coefficient Sensitivity of the Expected Returns to Market Returns where Cov( Ri, Rm ) i Var( R ) m : Expected Return of the Market : Market Risk Premium (the difference between the expected market rate of return and the risk-free rate of return) The assumptions and references for the calculation of the rates and coefficients above are explained below: i) Risk Free Rate (R f ) As the representative of the risk free rate, Turkish Eurobond interest rates with the longest maturity (10 years) is chosen. EUROSTAT data for Turkey 14 has been used to calculate this rate. The 5-year period of 14 http://epp.eurostat.ec.europa.eu/tgm/table.do?tab=table&init=1&plugin=1&language=en&pcode=tec00036

CDM Executive Board Page 22 [2007-2011] was assumed as the reference period. The arithmetic average of the annual averages for these years was accepted as the government bond yield rate; hence the risk free rate. This value was calculated as 13.51 %. ii) Beta Coefficient (β i ) Beta Coefficient was calculated using the data available form Istanbul Stock Exchange 15. Price Indices for XU100-BIST100 (General) and XELKT-BIST ELECTRICITY (Electricity Generating and Trading Companies) were collected and put into the relevant formula to calculate the Beta Coefficient. The value of the Beta Coefficient was found to be 0.798. The details of the calculation can be found in the separate spreadsheet file for the investment analysis supplied as an annex to PDD. iii) Market Risk Premium (E(R m ) R f ) To assess the market risk premium of Turkey, the studies of Aswoth Damodaran, a well-known independent researcher and an academician at the Stern School of Business at New York University, were used 16. Country Risk Premiums for Turkey for the same 5-year reference period above ([2007-2011]) were taken and their arithmetic average was accepted as the market risk premium of Turkey as at the end of 2011. The market risk premium value was found to be 10.09 %. iv) Expected Returns on Equity (Cost of Equity) (E(R i )) The expected returns on equity, the benchmark rate that would be used, was found, using the calculations above, as: E(R i ) = R f + β i (E(R m ) R f ) = 13.51 % + 0.798 * 10.09 % = 21.57 % So, the benchmark discount rate to be used in the investment analysis is 21.57 %. This rate can be assumed as reliable and conservative since it takes a period long enough (a five year period of [2007-2011]) as the reference and the beta coefficient takes all the companies in the electricity generation and trading sector that are quoted in Istanbul Stock Exchange (the number was 5 at the end of 2011) into account. The beta coefficient, hence the risk, for a single project of a single company is expected to be higher than that of a value calculated for 5 companies for a period of 5 years. A) Equity IRR Calculation for the Project The following assumptions were made in calculating the Equity IRR for the project: 1) The VER revenues were calculated assuming a GS-VER credit unit price of 8.00 USD/tCO 2 -eq, the average market value indicated for Turkey in the Ecosystem Marketplace State of the Voluntary Carbon Markets 2012 Report 17. This can be assumed as a fairly conservative price for Turkish Wind Energy Projects, since it also takes all other projects, mostly hydro, and projects developed under different standards, the price of which are generally lower than that of GS-VER Wind Energy Projects. 15 http://borsaistanbul.com/en/-nbsp-data-nbsp-/data/equity-market-data/index-data 16 http://pages.stern.nyu.edu/~adamodar/new_home_page/data.html 17 Ecosystem Marketplace State of the Voluntary Carbon Markets 2012 Report, page 56. (http://www.forest-trends.org/documents/files/doc_3164.pdf)

CDM Executive Board Page 23 2) The Energy Sales Unit Price was accepted as the guaranteed feed-in-tariff specified in the Law on Utilization of Renewable Energy Resources for the Purpose of Generating Electrical Energy (Law No: 5346, Issuance Date: 18.05.2005) 13, which is 7.3 USDcent/kWh. This price can be accepted as conservative, since it represents the minimum guaranteed price for electricity originating from wind energy projects. The price in the free electricity trade market is generally higher than that. 3) EUR/TRY Exchange Rate is calculated using the Turkish Central Bank data 18. This can be accepted as reliable and conservative since it assumes a period long enough (a five year period of [2007-2011]) as the reference. 4) EUR/USD Exchange Cross Rate is calculated using the Turkish Central Bank data 19. This can also be accepted as reliable and conservative since it assumes a period long enough (a five year period of [2007-2011]) as the reference. 5) The Average Expected Annual Electricity Generation Amount is calculated by multiplying the project generation of the project activity indicated in the licence by the ratio found by dividing the total firm generations of CDM-VER Wind Projects in Turkey by their total project generations for 2011, receiving the data from 2012 Capacity Projection Report of TEIAS 4. The firm energy generation capacity values in this report are based on actual generations of the power plants. By this way, the annual estimated firm energy generation capacity for the project is found. This can also be assumed as reliable and conservative, since it uses the official value from a government source, and takes all the wind farms similar to the project activity into account for a one-year period, a duration that is generally accepted long enough (minimum) for wind power feasibility studies. 6) To find the net amount of electricity generated by the project activity, the electricity drawn from the grid by the project should also be taken into account and subtracted from the amount of electricity fed into the grid. However, no reliable and official data could be found regarding the energy drawn from the grid by power plants. Hence, this estimated amount of energy drawn from the grid was simply ignored. This can also be assumed as acceptable since this drawn energy is small enough to be included in the error range of estimated energy fed into the grid. 7) The Euribor values used in the calculation for loan repayment and interests in the investment analysis were also received from a reliable source 20, and calculated for the same 5-year reference period ([2007-2011]), as in the other parameters. 8) The values for Service, Operation and Maintenance Costs were calculated taking the Aksu Wind Power Project Service and Availability Agreement with Wind Turbine Provider. 9) The values for credit were taken from the Credit Loan Agreement made between the Creditor Bank and the Project Proponent. 10) The project lifetime period was accepted as 20 years. A summary of the benchmark analysis and the relevant parameters can be found in the following table: 18 http://evds.tcmb.gov.tr/cgi-bin/famecgi?cgi=$ozetweb&dil=uk&araverigrup=bie_dkdovizgn.db 19 http://evds.tcmb.gov.tr/cgi-bin/famecgi?cgi=$ozetweb&dil=uk&araverigrup=bie_dkdovizgn.db 20 http://www.euribor-ebf.eu/euribor-org/euribor-rates.html

CDM Executive Board Page 24 Table 11. Summary of Benchmark Analysis and Financial Data Parameter Unit Value Reference / Source / Justification Installed Capacity MW 72 Project Activity Electricity Generation Licence Project Activity Electricity Generation Expected Annual Firm Licence, Firm/Project Generation Capacity MWh 194,003 Energy Generation Data of CDM-VER Wind Projects from 2012 Capacity Projection Report of TEIAS Carbon Credit Unit Price USD/tCO 2 -eq 8.00 Ecosystem Marketplace State of the Voluntary Carbon Markets 2012 Report Energy Unit Price USDcent/kWh 7.30 Law on Utilization of Renewable Energy Resources for the Purpose of Generating Electrical Energy (Law No: 5346, Issuance Date: 18.05.2005) Emission Factor tco 2 /MWh 0.611 Emission Factor Calculation, made according to Tool to calculate the emission factor for an electricity system-version 03.0.0 Risk Free Rate (R f ) % 13.50 EUROSTAT Data for Turkey for the 5-year period of [2007-2011] Beta Coefficient (β i ) - 0.798 Istanbul Stock Exchange Data for the 5-year Market Risk Premium (E(R m ) R f ) % 10.09 Benchmark Discount Rate (Expected Returns on Equity) % 21.57 period of [2007-2011] Data for Turkey for the 5-year period of [2007-2011] from Studies of Prof. Aswath Damodaran. Calculated using the relevant parameters according to the Capital Asset Pricing Model (CAPM). Turkish Central Bank Data for the 5-year EUR/TRY Exchange Rate - 2.0276 period of [2007-2011] EUR/USD Exchange Turkish Central Bank Data for the 5-year - 1.3916 Cross Rate period of [2007-2011] Total Investment Cost EUR 79,882,500 Investment Analysis Aksu Wind Power Project Service and Total Operation and EUR 29,083,252 Availability Agreement with Wind Turbine Maintenance Costs Provider Equity / Total Investment Cost Ratio % 23 Investment Analysis Debt / Total Investment Cost Ratio % 77 Investment Analysis Project Lifetime Years 20 Assumption Equity IRR % 9.38 Investment Analysis Cash Flow Comparison results of financial indicators can be summarized and depicted in the table below: Table 12. Comparison results of financial indicators Indicator Value Benchmark Discount Rate 21.57 %

CDM Executive Board Page 25 Equity IRR with Carbon Revenues 9.38 % Equity IRR without Carbon Revenues 7.16 % The results of the comparison show that without the extra income of carbon revenues, the Equity IRR of the project activity is equal to 7.16 % and lower than the benchmark discount rate, which is 21.57 %. This clearly indicates that the project activity cannot be considered as financially attractive. With carbon revenues, Equity IRR value is 9.38 %, which is also lower than the benchmark discount rate of 21.57 %. But carbon revenues give extra financial support to the project development and alleviate the financial hardships. Taking the VER Carbon Revenues into account brings some extra co-benefits to the project developer like fulfilling the Social Corporate Responsibility in an environment-friendly way, helping promote the image of the project developer, and increasing the chance of getting future incentives. Most importantly, additional financial income, extra detailed financial and environmental feasibility and documentation studies, and extra care taken in by developing the project as a CDM-VER Project greatly increases the probability of finding debt from a credit institution. Sub-step 2d: Sensitivity analysis (only applicable to Options II and III) A Sensitivity Analysis was made in order to show whether the conclusion regarding the financial/economic attractiveness is robust to reasonable variations in the critical assumptions. For this purpose, the sensitivity analysis is applied to following parameters: 1) Total Project Cost 2) Operational, Service and Maintenance Costs 3) Electrical Energy Generation 4) Electrical Energy Sales Price The sensitivity analysis was applied to these parameters for two cases, one with carbon revenues, and the other without carbon revenues; and for a range of ± 20 %, with increments of 5 %. The results are summarized in the table below: Table 13. Parameters and Variances Used in Sensitivity Analysis Variable Total Project Cost Variance -20% -15% -10% -5% 0% 5% 10% 15% 20% Amount (EUR) 61,882,737 65,750,408 69,618,079 73,485,750 77,353,421 81,221,092 85,088,763 88,956,434 92,824,105 IRR (with VER Revenues) IRR (without VER Revenues) 16.78% 14.50% 12.56% 10.86% 9.38% 8.07% 6.86% 5.80% 4.91% 13.78% 11.76% 10.02% 8.50% 7.16% 5.98% 4.92% 4.02% 3.25% Variable Operational, Service & Maintenance Costs Variance -20% -15% -10% -5% 0% 5% 10% 15% 20% Total Amount (EUR) IRR (with VER Revenues) IRR (without VER Revenues) 36,775,865 39,074,357 41,372,848 43,671,340 45,969,832 48,268,323 50,566,815 52,865,306 55,163,798 10.75% 10.41% 10.07% 9.73% 9.38% 9.04% 8.69% 8.34% 7.99% 8.55% 8.21% 7.86% 7.51% 7.16% 6.81% 6.46% 6.10% 5.74%

CDM Executive Board Page 26 Variable Electrical Energy Generation Variance -20% -15% -10% -5% 0% 5% 10% 15% 20% Amount (MWh) 155,202 164,902 174,602 184,302 194,003 203,703 213,403 223,103 232,803 IRR (with VER Revenues) IRR (without VER Revenues) 2.26% 4.09% 5.85% 7.61% 9.38% 11.16% 12.97% 14.79% 16.65% 0.33% 2.13% 3.86% 5.52% 7.16% 8.82% 10.49% 12.17% 13.87% Variable Electrical Energy Sales Price Variance -20% -15% -10% -5% 0% 5% 10% 15% 20% Amount (EURcent/kWh) IRR (with VER Revenues) IRR (without VER Revenues) 4.20 4.46 4.72 4.98 5.25 5.51 5.77 6.03 6.30 2.72% 4.42% 6.07% 7.72% 9.38% 11.05% 12.74% 14.45% 16.18% 0.33% 2.13% 3.86% 5.52% 7.16% 8.82% 10.49% 12.17% 13.87% The same results are also illustrated in the following figure: Figure 3. Sensitivity Analysis Results 25% 20% Sensitivity Analysis Benchmark Rate Project Costs with VER Project Costs without VER 15% IRR (%) 10% Operational Service & Maintenance Costs with VER Operational Service & Maintenance Costs without VER Electrical Energy Generation with VER 5% Electrical Energy Generation without VER Electrical Energy Sales Price with VER 0% -20% -15% -10% -5% 0% 5% 10% 15% 20% Sensitivity (%) Electrical Energy Sales Price without VER The results found in the sensitivity analysis indicated that under all alternative scenarios for all the parameters selected with different variances, the Equity IRR value could not reach the Benchmark Discount Rate of 21.57 %.

CDM Executive Board Page 27 Hence, the sensitivity analysis showed that the conclusion regarding financial/economic attractiveness of the project is robust to reasonable variations in the critical assumptions. The details of investment analysis can be found in the separate spreadsheet file supplied as an annex to this PDD. Outcome of Step 2: The project activity is unlikely to be financially/economically attractive. Step 3: Barrier analysis This step is not applied. Step 4: Common practice analysis According to Tool for the demonstration and assessment of additionality-version 07.0.0 (Hereafter referred to as The Tool in this section regarding the Common Practice Analysis) and Guidelines on common practice-version 02.0, (Hereafter referred to as The Guidelines in this section regarding the Common Practice Analysis), the Common Practice Analysis procedure was applied for the project activity. The project activity is a wind farm realizing power generation based on renewable energy. Hence, it falls under the category defined in the sub-clause (ii) in the Measure definition of the Tool (page 5) and sub-clause (b) in the Measure definition of the Guidelines (page 1): Switch of technology with or without change of energy source including energy efficiency improvement as well as use of renewable energies (example: energy efficiency improvements, power generation based on renewable energy); As a result, sub-step 4a was applied. Sub-step 4a: The proposed CDM project activity(ies) applies measure(s) that are listed in the definitions section above According the rules of the Guideline, the applicable geographical area is Turkey, and the output of the project activity is electricity. The stepwise approach for common practice described in the second section of the Guidelines was applied. For Step 1 of this stepwise approach, the calculation of the output range is done based on the installed capacity of the project. Since the installed capacity of the project is 72 MW, the output range will be 72 +/- 50 % = [36 108] MW. For Step2, firstly, identification of the similar projects was done according to the sub-paragraphs (a), (b), (c), (d) and (f) of paragraph 6 of the stepwise approach, as described on page 2-3 of the Guidelines. The result of this first phase is operational wind farms in Turkey at the date when the project activity is first commissioned. The below table shows these power plants:

CDM Executive Board Page 28 Table 14. Operational Wind Power Plants in Turkey as at the Date of Commissioning of the Project Wind Projects in Turkey (As at the Commissioning of the Project) Legal Status Power Plant Name Installed Capacity MW Location (Province) Commissioning Date VER Standard VER Standard Code / Number / Project ID 1 BOT ARES (ALAÇATI) 7.2 Izmir 2 BOT BORES (BOZCAADA) 10.2 Canakkale 3 AP SUNJÜT 1.2 Istanbul 2005-04-22 4 IPP ALİZE ENERJİ (DELTA PLASTİK) 1.5 Izmir 5 IPP ERTÜRK ELEKT. (TEPE) 0.9 Istanbul 2006-12-22 6 IPP ALİZE ENERJİ (ÇAMSEKİ) 20.8 Canakkale 2009-06-24 GS GS399 7 IPP ALİZE ENERJİ (KELTEPE) 20.7 Balikesir 2010-04-28 GS GS437 8 IPP ALİZE ENERJİ (SARIKAYA ŞARKÖY) 28.8 Tekirdag 2009-10-19 GS GS577 9 IPP AK ENERJİ AYYILDIZ (BANDIRMA) 15.0 Balikesir 2009-07-23 GS GS634 1 0 IPP AKDENİZ ELEK. MERSİN RES 33.0 Mersin 2010-03-19 GS GS753 1 1 IPP AKRES (AKHİSAR RÜZGAR) 43.8 Manisa 2011-09-23 GS GS955 1 2 IPP ANEMON ENERJİ (İNTEPE) 30.4 Canakkale 2007-11-22 GS GS347 1 3 IPP ASMAKİNSAN (BANDIRMA-3 RES) 24.0 Balikesir 2010-03-26 GS GS683 1 4 IPP AYEN ENERJİ (AKBÜK) 31.5 Aydin 2009-04-03 GS GS436 1 5 IPP AYVACIK (AYRES) 5.0 Canakkale 2011-10-23 GS GS956 1 6 IPP BAKRAS ELEK.ŞENBÜK RES 15.0 Hatay 2010-04-22 GS GS733 1 7 1 8 1 9 2 0 2 1 2 2 2 3 2 4 2 5 2 6 IPP BARES (BANDIRMA) 30.0 Balikesir 2011-08-11 GS, VER+ GS1072, 52-1 IPP BELEN HATAY 36.0 Hatay 2010-09-02 GS GS390 IPP BERGAMA RES (ALİAĞA RES) 90.0 Izmir 2010-06-16 GS GS735 IPP BORASKO BANDIRMA 60.0 Balikesir 2010-06-30 GS GS744 IPP BOREAS EN.(ENEZ RES) 15.0 Edirne 2010-04-09 GS GS702 IPP ÇANAKKALE RES (ENERJİ-SA) 29.9 Canakkale 2011-05-06 GS GS906 IPP ÇATALTEPE (ALİZE EN.) 16.0 Balikesir 2011-04-19 GS GS574 IPP DOĞAL ENERJİ (BURGAZ) 14.9 Canakkale 2008-05-08 GS GS439 IPP DENİZLİ ELEKT. (Karakurt- Akhisar) 10.8 Manisa 2007-05-28 VCS, VER+ IPP MARE MANASTIR 39.2 Izmir 2007-04-13 GS GS368 66

CDM Executive Board Page 29 2 7 2 8 2 9 3 0 3 1 3 2 3 3 3 4 3 5 3 6 3 7 3 8 3 9 4 0 4 1 4 2 4 3 4 4 4 5 4 6 4 7 4 8 4 9 5 0 5 1 IPP MAZI 3 30.0 Izmir 2010-06-18 GS GS388 IPP KİLLİK RES (PEM EN.) 40.0 Tokat 2011-12-17 GS GS947 IPP KORES KOCADAĞ 15.0 Izmir 2009-12-23 GS GS601 IPP KUYUCAK (ALİZE ENER.) 25.6 Manisa 2010-12-09 GS GS576 IPP ROTOR (OSMANİYE RES- GÖKÇEDAĞ RES) 135.0 Osmaniye 2010-10-15 GS GS474 IPP BAKİ ELEKTRİK ŞAMLI RÜZGAR 114.0 Balikesir 2011-11-13 GS GS351 IPP DATÇA RES 29.6 Mugla 2009-12-24 GS GS438 IPP ERTÜRK ELEKT. (ÇATALCA) 60.0 Istanbul 2008-12-27 GS GS367 IPP İNNORES ELEK. YUNTDAĞ 52.5 Izmir 2011-09-27 GS GS352 IPP LODOS RES (TAŞOLUK)KEMERBURGAZ 24.0 Istanbul 2008-08-20 GS GS503 IPP SARES (GARET ENER.) 22.5 Canakkale 2011-03-10 GS GS963 IPP IPP SAYALAR RÜZGAR (DOĞAL ENERJİ) SEBENOBA (DENİZ ELEK.)SAMANDAĞ 34.2 Manisa 2009-09-06 GS GS369 30.0 Hatay 2010-03-12 VCS, VER+ IPP SEYİTALİ RES (DORUK EN.) 30.0 Izmir 2011-07-22 GS GS578 IPP SOMA RES 116.1 Manisa 2011-12-09 GS GS398 IPP SOMA RES (BİLGİN ELEK.) 90.0 Manisa 2010-11-11 GS GS655 IPP SUSURLUK (ALANTEK EN.) 45.0 Balikesir 2011-05-20 GS GS854 IPP ŞAH RES (GALATA WIND) 93.0 Balikesir 2011-07-29 GS GS905 IPP TURGUTTEPE RES (SABAŞ ELEK.) 553 24.0 Aydin 2011-03-04 GS GS610 IPP ÜTOPYA ELEKTRİK 30.0 Izmir 2010-09-03 GS GS672 IPP ZİYARET RES 57.5 Hatay 2011-11-24 GS GS617 IPP SÖKE-ÇATALBÜK RES 30.0 Aydin 2012-01-08 GS GS653 IPP BOZYAKA RES 12.0 Izmir 2012-03-12 GS Markit GS Registry ID: 103000000 001624 IPP METRİSTEPE RES 27.5 Bilecik 2012-03-12 GS GS1067 IPP KAYADÜZÜ RES 7.5 Amasya 2012-03-16 GS GS950 Abbreviations: BOT: Build-Operate-Transfer, AP: Autoproducer, IPP: Independent Power Producer, VER: Verified Emission Reduction, GS: Gold Standard, VCS: Verified Carbon Standard

CDM Executive Board Page 30 47 wind farms were operational at the end of 2011 21. Four more wind farms had become operational in 2012 when the project activity was commissioned 22. As can be seen from the table, most of the wind farms (46 of 51) have been developed as CDM project activities. Only 5 wind farms are non-cdm projects. The reasons for their being non-cdm wind power projects is due to their legal status (BOT or Autoproducer), their early commissioning before the applicability of VER scheme or their small installed capacity size. If we apply the output range criterion for the identification of similar projects, as indicated in subparagraph (e) of paragraph 6 of the stepwise approach, all these 5 non-cdm projects will be eliminated, along with some of the CDM projects. If we further proceed with Steps (3), (4) and (5) of the same stepwise approach, as explained in the paragraphs, (7), (8) and (9) of the stepwise approach of the Guideline, we will see that no projects can be identified as similar to the project. Hence N all = 0, N diff = 0, and the formula F = 1- N diff /N all becomes not applicable. Also, as per the paragraph (10), F is indefinite and N all - N diff = 0 is less than 3. So, the proposed project activity is not a common practice. Hence, no similar projects could be found according to the Common Practice Analysis made according to the Tool and the Guidelines, the project activity is not common practice. Outcome of Step 4: The outcome of Step 4 is that the proposed project activity is not regarded as common practice, hence, the proposed project activity is additional. B.6. Emission reductions B.6.1. Explanation of methodological choices To establish the baseline scenario for the project, and to calculate the baseline emissions, project emissions, leakage and emission reductions, the latest version of the official methodology, ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0 (Hereafter referred to as The Methodology in this section regarding the Emission reductions) and the latest version of the official tool Tool to calculate the emission factor for an electricity system Version 03.0.0 (Hereafter referred to as The Tool in this section regarding the Emission reductions) were used. The applicability of ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0 (The Methodology) is justified according to the explanation given under the heading of Applicability on pages 2 and 3 of the Methodology, as follows: Applicability This methodology is applicable to grid-connected renewable power generation project activities that: (a) install a new power plant at a site where no renewable power plant was operated prior to the 21 Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021), Annex-1: Current System (As at the end of 2011) pp 109-123. (http://www.teias.gov.tr/kapasiteprojeksiyonuaralik2012.pdf) 22 http://www.enerji.gov.tr/yayinlar_raporlar/2012_yili_enerji_yatirimlari.xls

CDM Executive Board Page 31 implementation of the project activity (greenfield plant); (b) involve a capacity addition; (c) involve a retrofit of (an) existing plant(s); or (d) involve a replacement of (an) existing plant(s). The methodology is applicable under the following conditions: The project activity is the installation, capacity addition, retrofit or replacement of a power plant/unit of one of the following types: hydro power plant/unit (either with a run-of-river reservoir or an accumulation reservoir), wind power plant/unit, geothermal power plant/unit, solar power plant/unit, wave power plant/unit or tidal power plant/unit; Since the project is wind power greenfield plant, the Methodology is applicable. Baseline Scenario is also identified according to the rules under the heading of Baseline Methodology Procedure on page 4 of the Methodology: Identification of the baseline scenario If the project activity is the installation of a new grid-connected renewable power plant/unit, the baseline scenario is the following: Electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources, as reflected in the combined margin (CM) calculations described in the Tool to calculate the emission factor for an electricity system. Since the project activity is a wind power plant, project emissions are accepted as zero, PE y = 0. The project activity involves no emissions, except from a diesel generator used for emergency backup purposes. The possible emissions from the use of fossil fuels for the back up or emergency purposes by the operation of this diesel generator are neglected according to the methodology. Leakage emissions are also neglected as per the Methodology. Baseline emissions are considered according to the following explanations and formulas included in the Methodology: Baseline emissions Baseline emissions include only CO 2 emissions from electricity generation in fossil fuel fired power plants that are displaced due to the project activity. The methodology assumes that all project electricity generation above baseline levels would have been generated by existing grid-connected power plants and the addition of new grid-connected power plants. The baseline emissions are to be calculated as follows: BE y EGPJ, y * EFgrid, CM, y (1) Where: BE = Baseline emissions in year y (tco 2 /yr) y EG PJ, = Quantity of net electricity generation that is produced and fed into the grid as a result y of the implementation of the CDM project activity in year y (MWh/yr) EF = Combined margin CO 2 emission factor for grid connected power generation in year y grid, CM, y calculated using the latest version of the Tool to calculate the emission factor for an electricity system (tco 2 /MWh) Calculation of EG PJ,y

CDM Executive Board Page 32 The calculation of EG PJ,y is different for: (a) greenfield plants, (b) retrofits and replacements; and (c) capacity additions. These cases are described next. (a) Greenfield renewable energy power plants If the project activity is the installation of a new grid-connected renewable power plant/unit at a site where no renewable power plant was operated prior to the implementation of the project activity, then: EG EG (2) PJ, y facility, y Emission reduction calculations are similarly based on the relevant section of the Methodology: Emission reductions Emission reductions are calculated as follows: ER y BE PE (3) y y Where: ER = Emission reductions in year y (tco 2 e/yr) y BE = Baseline emissions in year y (tco 2 /yr) y PE = Project emissions in year y (tco 2 e/yr) y Estimation of emissions reductions prior to validation Project participants should prepare as part of the CDM-PDD an estimate of likely emission reductions for the proposed crediting period. This estimate should, in principle, employ the same methodology as selected above. Where the grid emission factor (EF CM,grid,y ) is determined ex post during monitoring, project participants may use models or other tools to estimate the emission reductions prior to validation. Since PE y = 0, ER y = BE y. So, in order to calculate the emission reductions for the project, it will suffice to calculate the baseline emissions. Calculation of the baseline emissions was done according to the Tool as indicated in the Methodology. Six-steps in the stepwise baseline methodology procedure in the Tool were followed to calculate the baseline emissions: Baseline methodology procedure 13. Project participants shall apply the following six steps: (a) STEP 1: identify the relevant electricity systems; (b) STEP 2: choose whether to include off-grid power plants in the project electricity system (optional); (c) STEP 3: select a method to determine the operating margin (OM); (d) STEP 4: calculate the operating margin emission factor according to the selected method; (e) STEP 5: calculate the build margin (BM) emission factor;

CDM Executive Board Page 33 (f) STEP 6: calculate the combined margin (CM) emission factor. Step 1: Identify the relevant electricity systems In the Tool, on page 5-6, the project electricity system is defined as: A grid/project electricity system - is defined by the spatial extent of the power plants that are physically connected through transmission and distribution lines to the project activity (e.g. the renewable power plant location or the consumers where electricity is being saved) and that can be dispatched without significant transmission constraints; Also, on page 6 of the Tool, connected electricity system is defined as: Connected electricity system - is an electricity system that is connected by transmission lines to the project electricity system. Power plants within the connected electricity system can be dispatched without significant transmission constraints but transmission to the project electricity system has significant transmission constraint, and/or the transmission capacity of the transmission line(s) that is connecting electricity systems is less than 10 per cent of the installed capacity either of the project electricity system or of the connected electricity system, whichever is smaller; The project activity is connected to the national grid of Turkey. There is no DNA in Turkey which has published a delinaeation of the project electricity system and the connected electricity systems. Since such information is not available, the criteria for the transmission constraints suggested on page 7 of the Tool were used to clarify the definitions of the project electricity system and the connected electricity systems. There are no available spot electricity markets in Turkey at the time of writing of this report. Also, there are no official data on availability or operational time of transmission lines in Turkey. Hence, these two criteria are not applicable. There are interconnections between Turkey and all its neighbouring countries. However, these lines are in limited capacity and have significant transmission constraints as compared to national transmission lines in Turkey. 23,24 In addition, international electricity trade through these transboundary transmission lines has legal restrictions and is subject to permission of EMRA (Republic of Turkey Energy Market Regulatory Authority). 25,26,27 The Turkish National Grid is operated by the responsible authority of TEIAS (Turkish Electricity Transmission Corporation). All the power plants in this system can be dispatched without significant transmission constraints. There are no layered dispatch systems (e.g. provincial/regional/national) within this national system. 28,29,30 So, there are no independent separate grids in the national grid. In the light of above information and the paragraphs (17) and (18) on the page 7 of the Tool, the project electricity system is defined as Turkish National Grid, and the connected electricity systems are defined 23 http://www.teias.gov.tr/dosyalar/nettransferkapasiteleri.doc 24 http://212.175.131.171/makaleler/entsoe%20bağlantısı%20icci%20v3.pdf 25 http://www.epdk.gov.tr/documents/elektrik/mevzuat/yonetmelik/elektrik/ithalat_ihracat/elk_ynt_ithalat_ihracat_sonhali.doc 26 http://www.epdk.gov.tr/documents/elektrik/mevzuat/yonetmelik/elektrik/ithalat_ihracat/iliskili_mevzuat/kapasitetahsisiesaslar.doc 27 http://www.epdk.gov.tr/index.php/elektrik-piyasasi/lisans?id=818 28 http://www.teias.gov.tr/hakkimizda.aspx 29 http://212.175.131.171/faaliyet2011/ing_teias.pdf 30 http://geni.org/globalenergy/library/national_energy_grid/turkey/

CDM Executive Board Page 34 as the neighbouring countries of Turkey, all of which are connected to Turkish national grid by transboundary transmission lines. As per the paragraphs (19), (20), (21), (22) and (23) on page 8 of the Tool, electricity imports and exports and their usage in the emission calculations are defined. For the purpose of determining the operating margin emission factor, the CO 2 emission factor for net electricity imports from the connected electricity systems is accepted as 0 t CO 2 /MWh according to paragraph (21), sub-paragraph (a) of the Tool, and the electricity exports are not subtracted from electricity generation data used for calculating and monitoring the electricity emission factors according to paragraph (23) of the Tool. Step 2: Choose whether to include off-grid power plants in the project electricity system (optional) The Tool suggests two options between which the project participants may choose to calculate the operating margin and build margin emission factor: Option I Option II : Only grid power plants are included in the calculation. : Both grid power plants and off-grid power plants are included in the calculation. The rationale behind Option II is explained in the Tool as Option II provides the option to include offgrid power generation in the grid emission factor. Option II aims to reflect that in some countries offgrid power generation is significant and can partially be displaced by CDM project activities, that is if off-grid power plants are operated due to an unreliable and unstable electricity grid. This is not the case for the National Grid of Turkey, the selected project system. The contribution of the off-grid power plants to Turkish grid is negligible and no official or reliable data regarding the off-grid power plants in Turkey could be found. So, Option II is not appropriate. Hence, Option I is selected and only grid power plants are included in the calculation of the operating margin and build margin emission factors. Step 3: Select a method to determine the operating margin (OM) The Tool gives four following method options for the calculation of the operating margin emission factor (EF grid,om,y ): (a) Simple OM, or (b) Simple adjusted OM, or (c) Dispatch data analysis OM, or (d) Average OM Since power plant specific data for generation, emission or emission factor are not available, Simple adjusted OM and Dispatch data analysis OM methods are not applicable. This also renders Option A of Simple OM method not applicable. The remaining two methods are Option B of Simple OM and Average OM methods. To decide between these two alternative methods, we have to take the situation of low-cost/must-run power plants into account. Following table summarizes the generation amounts and percentage of low-cost/must-run power plants for the five most recent years available at the time of writing of this report, that is, the period of [2007 2011]. Table 15. The Contribution of Low-Cost/Must-Run Power Plants to the Gross Generation of Turkey for the 5-year period of [2007 2011]

CDM Executive Board Page 35 Gross Generations and Percentages by Fuel Types and Primary Energy Resources of Low-Cost/Must-Run Power Units in Turkey (Unit: GWh) Primary Energy Resource or Fuel Type Years 2007 2008 2009 2010 2011 5-Year Total 5-Year Percentage Hard Coal + Imported Coal + Asphaltite 15,136.2 15,857.5 16,595.6 19,104.3 27,347.5 94,041.1 9.17% Lignite 38,294.7 41,858.1 39,089.5 35,942.1 38,870.4 194,054.8 18.92% Total Coal 53,430.9 57,715.6 55,685.1 55,046.4 66,217.9 288,095.8 28.10% Fuel-Oil 6,469.6 7,208.6 4,439.8 2,143.8 900.5 21,162.3 2.06% Diesel Oil 13.3 266.3 345.8 4.3 3.1 632.8 0.06% LPG 0.0 0.0 0.4 0.0 0.0 0.4 0.00% Naphtha 43.9 43.6 17.6 31.9 0.0 137.0 0.01% Total Oil (Liquid Total) 6,526.8 7,518.5 4,803.5 2,180.0 903.6 21,932.4 2.14% Natural Gas 95,024.8 98,685.3 96,094.7 98,143.7 104,047. 6 491,996.1 47.98% Renewables and Wastes 213.7 219.9 340.1 457.5 469.2 1,700.5 0.17% Thermal 155,196. 2 164,139. 3 156,923. 4 155,827. 6 171,638. 3 803,724.8 78.38% Hydro + Geothermal + Wind Total 36,361.9 34,278.7 37,889.5 55,380.1 57,756.8 221,667.0 21.62% Hydro 35,850.8 33,269.8 35,958.4 51,795.5 52,338.6 209,213.1 20.40% Geothermal + Wind 511.1 1,008.9 1,931.1 3,584.6 5,418.2 12,453.9 1.21% General Total (Gross) 191,558. 1 198,418. 0 194,812. 9 211,207. 7 229,395. 1 1,025,391. 8 100.00% Gross - Low-Cost/Must-Run 36,361.9 34,278.7 37,889.5 55,380.1 57,756.8 221,667.0 21.62% Gross Excluding Low-Cost/Must-Run (Thermal) 155,196. 2 164,139. 3 156,923. 4 155,827. 6 171,638. 3 803,724.8 78.38% The selection of the low-cost/must run power plants was done according to the definition on page 6 of the Tool: Low-cost/must-run resources - are defined as power plants with low marginal generation costs or dispatched independently of the daily or seasonal load of the grid. They include hydro, geothermal, wind, low-cost biomass, nuclear and solar generation. If a fossil fuel plant is dispatched independently of the daily or seasonal load of the grid and if this can be demonstrated based on the publicly available data, it should be considered as a low-cost/must-run; Hence, the selection in the table which assumes the total of hydro, geothermal and wind as the lowcost/must-run resources is justified. Since there are no nuclear power plants and also no grid-connected solar power plants in Turkey at the time of writing of this report, these resource types are automatically excluded. As can be seen from the table, low-cost/must-run resources constitute less than 50 per cent of total grid generation (excluding electricity generated by off-grid power plants) in average of the five most recent years [2007 2011], which is in line with the relevant rule, paragraph 34 on page 9 10 of the Tool:

CDM Executive Board Page 36 The simple OM method (Option a) can only be used if low-cost/must-run resources constitute less than 50 per cent of total grid generation (excluding electricity generated by off-grid power plants) in: 1) average of the five most recent years, or 2) based on long-term averages for hydroelectricity production. The rules for the usability of Simple OM method Option, which was stated in paragraph 42, on page 11 of the Tool, as below, are also met: 42. Option B can only be used if: (a) The necessary data for Option A is not available; and (b) Only nuclear and renewable power generation are considered as low-cost/must-run power sources and the quantity of electricity supplied to the grid by these sources is known; and (c) Off-grid power plants are not included in the calculation (i.e. if Option I has been chosen in Step 2). As a result, Option B of Simple OM method was selected as the method to determine the operating margin. Ex ante option was preferred to calculate the emissions factor, and the reference period was selected as the three-year period of [2009 2011], as per the requirements stated in paragraph 36, sub-paragraph (a) on page 10 of the Tool: 36. For the simple OM, the simple adjusted OM and the average OM, the emissions factor can be calculated using either of the two following data vintages: (a) Ex ante option: if the ex ante option is chosen, the emission factor is determined once at the validation stage, thus no monitoring and recalculation of the emissions factor during the crediting period is required. For grid power plants, use 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. For off-grid power plants, use a single calendar year within the five most recent calendar years prior to the time of submission of the CDM-PDD for validation; Step 4: Calculate the operating margin emission factor according to the selected method Operating Margin Emission Factor was calculated using the formulation and procedure described in the paragraphs (49) and (50) in sub-section 6.4.1.2., on pages 14 15 of the Tool: 6.4.1.2. Option B: Calculation based on total fuel consumption and electricity generation of the system 49. 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: EF grid, OMsimple, y i FC i, y NCV EG i, y y EF CO2, i, y Equation (7)

CDM Executive Board Page 37 Where: EF grid,omsimple, y FC i,y NCV i,y = Simple operating margin CO2 emission factor in year y (t CO2/MWh) = Amount of fuel type i consumed in the project electricity system in year y (mass or volume unit) = Net calorific value (energy content) of fuel type i in year y (GJ/mass or volume unit) EF CO2,i,y = CO 2 emission factor of fuel type i in year y (t CO 2 /GJ) EG y = 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 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 50. 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 imports5 to the grid. Electricity imports should be treated as one power plant m. Fossil fuel types and their amounts were taken from the official data of Electricity Generation & Transmission Statistics of Turkey, published by TEIAS (Turkish Electricity Transmission Company, the state authority responsible for the national transmission system of Turkey), as indicated in the table below 1 : Table 16. Fuel Consumption in Electricity Generation in Turkey for the 3-year period of [2009 2011] Fuel Consumption in Electricity Generation Excluding Low- Cost/Must-Run (Unit: Ton (solid and liquid) /10 3 m 3 (gas)) Years 2007 2008 2009 2010 2011 Hard Coal+Imported Coal+Asphaltite 6,029,143.0 6,270,008.0 6,621,177.0 7,419,703.0 10,574,434.0 Lignite 61,223,821.0 66,374,120.0 63,620,518.0 56,689,392.0 61,507,310.0 Fuel Oil 2,250,686.0 2,173,371.0 1,594,321.0 891,782.0 531,608.0 Diesel oil 50,233.0 131,206.0 180,857.0 20,354.0 15,047.0 LPG 0.0 0.0 111.0 0.0 0.0 Naphtha 11,441.0 10,606.0 8,077.0 13,140.0 0.0 Natural Gas 20,457,793.0 21,607,635.0 20,978,040.0 21,783,414.0 22,804,587.0 Renewables and Wastes* * Since heating values and fuel amounts of renewable and waste materials are not included in TEIAS Statistics, these are also ignored here. To calculate the Net Calorific Values, data on heating values of fuels consumed in thermal power plants in Turkey by the electric utilities 31 along with the fuel amounts mentioned above were used. 31 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2011/yakıt46-49/49.xls

CDM Executive Board Page 38 Table 17. Heating Values of Fuels Consumed in Thermal Power Plants in Turkey by the Electric Utilities [2006 2011] Heating Values of Fuels Consumed Years in Thermal Power Plants (Unit: Tcal) 2007 2008 2009 2010 2011 Hard Coal+Imported Coal+Asphaltite 32,115.0 33,310.0 35,129.8 39,546.5 57,567.3 Lignite 100,320.0 108,227.0 97,651.6 96,551.0 107,209.5 Fuel Oil 21,434.0 20,607.0 15,159.9 8,569.1 5,279.9 Diesel oil 517.0 1,328.0 1,830.2 209.5 155.1 LPG 0.0 0.0 1.2 0.0 0.0 Naphtha 118.0 113.0 84.2 105.1 0.0 Natural Gas 179,634.0 189,057.0 186,265.8 194,487.3 202,064.1 Renewables and Wastes* Turkey's Thermal Total 334,138.0 352,642.0 336,122.7 339,468.5 372,275.9 * Since heating values and fuel amounts of renewable and waste materials are not included in TEIAS Statistics, these are also ignored here. Since there are no plant-specific or fuel-type specific emission factor data officially available in Turkey, we have to use the emission factors published by IPCC. 32 The related emission factors are indicated in the following table: Table 18. IPCC Default Emission Factor Values by Different Fuel Types Default CO 2 Emission Factors for Combustion Table 1.4 Effective CO 2 Emission Factor (kg/tj) Fuel Type Default Lower Upper Anthracite 98,300 94,600 101,000 Coking Coal 94,600 87,300 101,000 Other Bituminous Coal 94,600 89,500 99,700 Sub-Bituminous Coal 96,100 92,800 100,000 Lignite 101,000 90,900 115,000 Fuel Oil 77,400 75,500 78,800 Diesel Oil 74,100 72,600 74,800 LPG 63,100 61,600 65,600 Naphtha 73,300 69,300 76,300 Natural Gas 56,100 54,300 58,300 For the sake of conservativeness, the lower limits of the 95 percent confidence intervals were used in the calculation of Operating Margin Emission Factor. Since the emission factors of IPCC are based on mass-units, and the fuel consumption amounts for natural gas is given in volume units in TEIAS statistics, we should convert the amount of natural gas from volume units to mass units. For this purpose, the density of natural gas must be specified. Natural 32 http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_volume2/v2_1_ch1_introduction.pdf

CDM Executive Board Page 39 Gas Density of Turkey for Electricity Generation was calculated using the data for Turkey in International Energy Agency s (IEA) Natural Gas Information (2010 Edition) 33, IEA Key World Energy Statistics 2011 34, and IEA Energy Statistics Manual 35. Turkey s main natural gas supplier is Russian Federation, along with its neighbouring countries 36. This fact is also confirmed by IEA Natural Gas Information 33 by comparing average gross calorific value of natural gas of Turkey for consumption and that of Russian Federation for production. So, natural gas produced and exported by Russian Federation and imported and consumed by Turkey was accepted as the representative of natural gas used as fuel in electricity generation in Turkish National Grid. To calculate the density of natural gas, the following table 33 was used: Table 19. Conversion Factors from Mass or Volume to Heat (Gross Calorific Value) for Natural Gas Supplied by Russian Federation GAS Russia To: MJ Btu From: multiply by: cm* 38.23 36,235 Kg 55.25 52,363 * Standard Cubic Meters This gives us a natural gas density of 0.692 kg/m 3, which we used to calculate the mass of natural gas used as fuel in power plants in Turkey for electricity generation. As a result, the Fuel Consumption in Electricity Generation in Turkey can be shown again with all the amounts in mass units as in the following table: Table 20. Fuel Consumption in Electricity Generation in Turkey for the 3-year period of [2009 2011] (in mass units) Fuel Consumption in Electricity Generation Excluding Low- Cost/Must-Run (Unit: Ton) Years 2007 2008 2009 2010 2011 Hard Coal+Imported Coal+Asphaltite 6,029,143.0 6,270,008.0 6,621,177.0 7,419,703.0 10,574,434.0 Lignite 61,223,821.0 66,374,120.0 63,620,518.0 56,689,392.0 61,507,310.0 Fuel Oil 2,250,686.0 2,173,371.0 1,594,321.0 891,782.0 531,608.0 Diesel oil 50,233.0 131,206.0 180,857.0 20,354.0 15,047.0 LPG 0.0 0.0 111.0 0.0 0.0 Naphtha 11,441.0 10,606.0 8,077.0 13,140.0 0.0 33 IEA Statistics, Natural Gas Information 2010, International Energy Agency - Introductory Information, Section 7, Abbreviations and conversion factors, pp. xxvii - xxx. 34 http://www.iea.org/publications/freepublications/publication/key_world_energy_stats-1.pdf, Conversion Factors, pp. 58 60. 35 http://www.iea.org/publications/freepublications/publication/statistics_manual.pdf, Annex 3 Units and Conversion Equivalents Natural Gas pp. 182 183. 36 BOTAS (Petroleum Pipeline Corporation) Natural Gas Purchase Agreements Information (http://www.botas.gov.tr/)

CDM Executive Board Page 40 Natural Gas 14,155,681.9 14,951,310.2 14,515,664.6 15,072,939.7 15,779,535.9 Renewables and Wastes* Turkey's Thermal Total 83,721,005.9 89,910,621.2 86,540,725.6 80,107,310.7 88,407,934.9 * Since heating values and fuel amounts of renewable and waste materials are not included in TEIAS Statistics, these are also ignored here. Net Calorific Values can be calculated using the heating values and the fuel amounts: Table 21. Net Calorific Values calculated for fuel types in Electricity Generation in Turkey for the 3-year period of [2009 2011] Net Calorific Values of Fuels Years Consumed in Thermal Power Plants (Unit: TJ/Gg) 2007 2008 2009 2010 2011 Hard Coal+Imported Coal+Asphaltite 22.3 22.2 22.2 22.3 22.8 Lignite 6.9 6.8 6.4 7.1 7.3 Fuel Oil 39.9 39.7 39.8 40.2 41.6 Diesel oil 43.1 42.4 42.4 43.1 43.2 LPG 0.0 0.0 46.5 0.0 0.0 Naphtha 43.2 44.6 43.6 33.5 0.0 Natural Gas 53.1 52.9 53.7 54.0 53.6 Renewables and Wastes* 0.0 0.0 0.0 0.0 0.0 * Assumed as zero due to unavailability of data and conservativeness It is not very clear whether the heating values given in TEIAS statisitics 31 are lower heating values (Net Calorific Values = NCV) or higher heating values (Gross Calorific Values = GCV). However, some other sources of state, academic and NGO (chamber of engineers) origin confirm that these are lower heating values (net calorific values) by giving values in the same range as the calculated NCV values 37,38,39,40,41,42. Moreover, these data is compliant with the value given in National Inventory Reports and Common Report Formats of Turkey submitted to UNFCCC, in which it was also stated that the heating values given are NCV values 43,44. As a result, these values are assumed to be the net calorific values of thermal power plants in Turkey for the relevant period. Turkey s Net Electricity Generation by primary energy resources was not given in the TEIAS Turkish Electricity Generation Transmission Statistics 45. Instead, Gross Electricity Generation by primary 37 http://enver.eie.gov.tr/docobjects/download/60094/tephesap.xls 38 http://www.hkad.org/makaleler/cilt1/sayi1/hkad-12-004.pdf 39 http://www.enerji.gov.tr/yayinlar_raporlar/sektor_raporu_tki_2011.pdf 40 http://www.mmo.org.tr/resimler/dosya_ekler/a9393ba5ea45a12_ek.pdf 41 http://www.mmo.org.tr/resimler/dosya_ekler/b4d09fdaf9131ab_ek.pdf?dergi=1148 42 http://tez.sdu.edu.tr/tezler/tf00997.pdf 43 http://unfccc.int/files/national_reports/annex_i_ghg_inventories/national_inventories_submissions/application/zip/tur-2013-nir- 15apr.zip 44 http://unfccc.int/files/national_reports/annex_i_ghg_inventories/national_inventories_submissions/application/zip/tur-2013-crf- 12apr.zip 45 http://www.teias.gov.tr/istatistikler.aspx, http://www.teias.gov.tr/eng/statisticalreports.aspx

CDM Executive Board Page 41 energy resources 46, net generation amount and percentages for the whole national grid regardless of the primary energy resources are available 47. As a result, it becomes necessary to calculate the net generation by primary energy resources by using these two data sets available. For this purpose, the net/gross electricity generation ratio was assumed to be the same for all primary energy resources. According to some studies made on this subject, the net/gross electricity generation ratio of renewable energy power plants is slightly higher than that of thermal power plants 48,49. Since the gross generation percentage of renewable energy power plants is lower than the percentage of thermal power plants, using the same average net/gross electricity generation ratio for all power plants would result in a slightly lower share for renewable energy power plants in the total net electricity generation than it would be if we used the actual net/gross electricity generation ratios. Likewise, the net generation share of thermal power plants will be slightly higher than that it would normally be. This would cause a slightly higher operational margin emission factor value for the whole system, if we used all the power plants including renewable ones, in the emission factor calculation. This would still be acceptable since the difference between net/gross electricity generation ratio of renewable and non-renewable power plants is very low (about 1 2 %), and could be assumed in the allowed error range. However, by choosing Option B of Simple OM method for operating margin emission factor calculation, we excluded all the low-cost/must-run power plants, that is, renewable ones. So, the impact of net/gross electricity generation ratio for renewable power plants is automatically eliminated. Since the corresponding ratio for different thermal plants is almost the same, using the same average net/gross electricity generation ratio for all thermal power plants is acceptable. The following table summarizes the calculation of net electricity generation from gross electricity generation distribution by primary energy resources and net/gross electricity generation ratio for all system. Table 22. Net Electricity Generation Calculation by Primary Energy Resources for Turkey for the 5-year period of [2007 2011] Gross & Net Generations and Percentages of Fuel Types and Primary Energy Resources (Unit: GWh) Primary Energy Resource or Fuel Type Years 2007 2008 2009 2010 2011 5-Year Total 5-Year Percentag e Hard Coal + Imported Coal + Asphaltite 15,136.2 15,857.5 16,595.6 19,104.3 27,347.5 94,041.1 9.17% Lignite 38,294.7 41,858.1 39,089.5 35,942.1 38,870.4 194,054.8 18.92% Total Coal 53,430.9 57,715.6 55,685.1 55,046.4 66,217.9 288,095.8 28.10% Fuel-Oil 6,469.6 7,208.6 4,439.8 2,143.8 900.5 21,162.3 2.06% Diesel Oil 13.3 266.3 345.8 4.3 3.1 632.8 0.06% LPG 0.0 0.0 0.4 0.0 0.0 0.4 0.00% Naphtha 43.9 43.6 17.6 31.9 0.0 137.0 0.01% Total Oil (Liquid Total) 6,526.8 7,518.5 4,803.5 2,180.0 903.6 21,932.4 2.14% Natural Gas 95,024.8 98,685.3 96,094.7 98,143.7 104,047. 6 491,996.1 47.98% Renewables and Wastes 213.7 219.9 340.1 457.5 469.2 1,700.5 0.17% 46 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2011/uretim%20tuketim(22-45)/40(06-11).xls 47 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2011/uretim%20tuketim(22-45)/33(84-11).xls 48 http://www.pserc.wisc.edu/documents/publications/special_interest_publications/epri_electricity_use_report_final_1024651. pdf, pp. 2-6 2-14. 49 ftp://ftp.eia.doe.gov/electricity/epatech.pdf, pp 2 4.

CDM Executive Board Page 42 Thermal 155,196. 2 164,139. 3 156,923. 4 155,827. 6 171,638. 3 803,724.8 78.38% Hydro + Geothermal + Wind Total 36,361.9 34,278.7 37,889.5 55,380.1 57,756.8 221,667.0 21.62% Hydro 35,850.8 33,269.8 35,958.4 51,795.5 52,338.6 209,213.1 20.40% Geothermal + Wind 511.1 1,008.9 1,931.1 3,584.6 5,418.2 12,453.9 1.21% Geothermal 162.4 435.7 668.2 694.3 1,960.7 0.19% Wind 846.5 1,495.4 2,916.4 4,723.9 9,982.1 0.97% General Total (Gross) General Total (Net) 191,558. 1 183,339. 7 198,418. 0 189,761. 9 194,812. 9 186,619. 3 211,207. 7 203,046. 1 229,395. 1 217,557. 7 Net / Gross Ratio 95.71% 95.64% 95.79% 96.14% 94.84% 95.60% 1,025,391.8 100.00% 980,324.7 95.60% Gross - Low-Cost/Must-Run 36,361.9 34,278.7 37,889.5 55,380.1 57,756.8 221,667.0 21.62% Gross Excluding Low-Cost/Must-Run (Thermal) 155,196. 2 164,139. 3 156,923. 4 155,827. 6 171,638. 3 Net - Low-Cost/Must-Run 34,801.9 32,783.3 36,295.9 53,240.1 54,776.4 211,897.5 Net Excluding Low-Cost/Must-Run (Thermal) 148,537. 8 156,978. 6 150,323. 4 149,806. 0 162,781. 3 803,724.8 78.38% 768,427.2 The operating margin emission factor was calculated using the above assumptions, data and formulations. The details are in the Section B.6.3. Ex ante calculation of emission reductions. Step 5: Calculate the build margin (BM) emission factor For this step, Option I indicated in paragraph 68 of the Tool was chosen and the build margin emission factor is calculated ex ante based on the most recent information available at the time of writing this report. Power plant based generation data is unavailable for Turkish National Grid. However, plant based generation capacity data is available in annually published Capacity Projection Reports of TEIAS 50. The latest of these reports, Turkish Electrical Energy 10-Year Generation Capacity Projection Report 2012 2021 (with definitive values of year 2011) 4 was used as the reference for build margin emission calculation. In this report, there are Project Generation Capacity and Firm Generation Capacity for each power plant. Project Generation Capacity is the value written on the generation licence given by EMRA for each power plant, and indicates the generation that could be achieved under ideal conditions. Firm Generation Capacity reflects the real generation capacity, taking into account various parameters that could affect the generation, and mostly based on the actual generations of the previous years. Hence, firm generation capacities of power plants indicated in this report were selected as the reference generation data for the build margin emission calculation. The total firm generation capacity in 2011 is calculated as 266,380.9 GWh 21, a figure higher than total gross generation of 229,395.1 GWh in 2011 46,47. This is expected, since the full annual firm generation capacities of power plants commissioned in 2011 have been taken into account. Since the real contribution of firm generation capacities of power plants commissioned in 2011 to real gross generation in 2011 is very hard to calculate, the firm generation capacities of all power plants at the end of 2011 is assumed as their gross generation in 2011, to calculate the build margin emission factor calculation. This is also in line with the logic behind the build margin emission factor calculation, that is, this assumption reflects the impact of power plants that started to supply electricity to the grid most recently better. 50 http://www.teias.gov.tr/kapasiteprojeksiyonu.aspx

CDM Executive Board Page 43 The Turkish Electrical Energy 10-Year Generation Capacity Projection Report 2012 2021 (with definitive values of year 2011) gives the definitive situation of the Turkish Energy Generation System as at the end of 2011. At this date, there were 643 power plants in Turkey 2,3,4. 618 of these were listed namely, 25 of them under the categorisation of Others in 5 different places in the Annex 1 of the report 21. So, since it is impossible to specify the names and commissioning dates of the power plants in the Others category, these were excluded in the build margin emission factor calculation. Capacity additions of retrofits of power plants were selected by comparing the installed capacity values and fuel types given in the capacity projection reports for different years 50, and explanations given in energy investment data of Ministry of Energy and Natural Resources of Turkey 51, which includes commissioning dates of all power plants in Turkey beginning from 2003. CDM-VER project activities in Turkey at the end of 2011 were specified by using the registry web sites of emission reduction standards used in Turkey, i.e. Gold Standard (GS), Verified Carbon Standard (VCS), and VER+ standards 52,53,54,55. A total of 125 power plants have been specified as CDM-VER Projects in Turkey listed in the registry sites of these standards. The commissioning of power plants in Turkey are often made in multiple stages, as allowed in the Electrical Installations Acceptance Bylaw 56. The rationale of this procedure is mostly to commission the part or group of the power plant that has been completed and ready to be commissioned without having to wait for all the power plant to be completed; and not to lose revenues from electricity sales in this period. These single stages of commissionings are called provisional acceptance and represents the date on which the electricity generated by the power plant started to be sold. As a result, these partial commissionings, which are the individual stages of commissioning process indicated by provisional acceptances, have to be taken into account to calculate the build margin emission factor correctly. For this reason, each single partial commissioning of a power plant was considered as a separate power unit. The project and firm generation of each power unit was found by multiplying the total project and firm generation of the power plant by the ratio found by dividing the installed capacity of the power unit by that of the whole power plant. The dates of commissionings, or power units, were taken from Capacity Projection Reports of TEIAS 50 and Energy Investment Data of Ministry of Energy 51. The commissionings were sorted by their dates beginning from the newest to the oldest to identify the two sets of power units SET 5-units, and SET 20 per cent, according to paragraph 71 on the page 20 of the Tool. The calculation of build margin emission factor calculation is done according to the paragraph 73 and 73, on pages 22 23 of the Tool: 51 http://www.enerji.gov.tr/index.php?dil=tr&sf=webpages&b=yayinlar_raporlar&bn=550&hn=&id=3273 52 http://goldstandard.apx.com/ 53 http://www.markit.com/sites/en/products/environmental/markit-environmental-registry-public-view.page 54 https://vcsprojectdatabase2.apx.com/mymodule/interactive.asp?tab=projects&a=1 55 http://www.netinform.de/ke/wegweiser/ebene1_projekte2.aspx?ebene1_id=49&mode=4 56 http://www.resmigazete.gov.tr/arsiv/22280.pdf, pp. 2 37.

CDM Executive Board Page 44 73. The build margin emissions factor is the generation-weighted average emission factor (t CO2/MWh) of all power units m during the most recent year y for which electricity generation data is available, calculated as follows: EF grid Where: EG m m, y EFEL, m, y, BM, y Equation (13) EG m m, y EF grid,bm,y EG m,y EF EL,m,y m y = Build margin CO 2 emission factor in year y (t CO 2 /MWh) = Net quantity of electricity generated and delivered to the grid by power unit m in year y (MWh) = CO 2 emission factor of power unit m in year y (t CO 2 /MWh) = Power units included in the build margin = Most recent historical year for which electricity generation data is available 74. The CO 2 emission factor of each power unit m (EF EL,m,y )should be determined as per the guidance in Step 4 section 6.4.1 for the simple OM, using Options A1, A2 or A3, 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. Since the power plant based data of emission factors and consumed fuels are not available, but generations and fuel types are available for the sample group of power units m used to calculate the build margin, only Option A2 of the Simple OM method is convenient for a calculation. So, emission factor for power plants for each fuel is calculated as indicated in the following sub-paragraph (b) of paragraph 44 on page 12 of the Tool: (b) Option A2 - If for a power unit m only data on electricity generation and the fuel types used is available, the emission factor should be determined based on the CO2 emission factor of the fuel type used and the efficiency of the power unit, as follows: EF EL, m, y EFCO, m, i, y 3.6 2 Equation (3) m, y Where: EF EL,m,y = CO 2 emission factor of power unit m in year y (t CO 2 /MWh) EF CO2,m,i,y = Average CO 2 emission factor of fuel type i used in power unit m in year y (t CO 2 /GJ) η m,y = Average net energy conversion efficiency of power unit m in year y (ratio) m = All power units serving the grid in year y except low-cost/must-run power units y = The relevant year as per the data vintage chosen in Step 3 For the average emission factor of fuel types, the emission factors published by IPCC 32 were taken as reference, and the lower limits of the 95 percent confidence intervals were used, as in the calculation of Operating Margin Emission Factor.

CDM Executive Board Page 45 For the average net energy conversion efficiency of the power units for each fuel type, Table 1 in Appendix 1 on page 33 of the Tool was taken as reference, as indicated in the table below. Table 23. IPCC Default Efficiency Factors for Grid Power Plants Appendix 1. Default efficiency factors for power plants - Table 1. Grid power plants Grid Power Plant Old Units New Generation Technology (before Units and in (after 2000) 2000) Coal - - Subcritical 37.0% 39.0% Supercritical - 45.0% Ultra-Supercriticial - 50.0% IGCC - 50.0% FBS 35.5% - CFBS 36.5% 40.0% PFBS - 41.5% Oil - - Steam turbine 37.5% 39.0% Open cycle 30.0% 39.5% Combined cycle 46.0% 46.0% Natural gas - - Steam turbine 37.5% 37.5% Open cycle 30.0% 39.5% Combined cycle 46.0% 60.0% For most of the power plants included in the build margin emission factor calculation, power-plant specific data could not be found. For these, the data in the above table was used and maximum applicable values considering conservativeness were taken. The values for new units (after 2000) were used. However, for the thermal power plants using imported coal that were in the build margin emission calculation set, the efficiency data had been able to be found 57. For these, generation-weighted average efficiency was calculated and this value is used in the build margin emission factor calculation, as indicated in the following table: Table 24. Efficiency Factors for Power Plants Using Imported Coal as the Fuel in the Sample Group used in the Build Margin Emission Calculation 57 Panel about Coal-Fired Power Plants and Investment Models, Middle East Technical University Alumni Association Visnelik Facility, 23 February 2013 / Saturday / 13:30, Presentation given by Muzaffer BASARAN, http://www.odtumd.org.tr/dosyaarsivi/etkinlik/muzaffer_basaran_odtu_komur_santral_230213.pptx, slides 31 40.

CDM Executive Board Page 46 Legal Status Fuel / Energy Source POWER PLANT NAME Installed Capacity MW Firm Generation Capacity (year 2012) GWh Commissioning Date Location (Province) Efficiency Firm Generation x Efficiency IPP IC BEKİRLİ TES (İÇDAŞ ELEKT.) 600.000 4,320.0 2011-12-15 Canakkale 41.5% 1,792.80 IPP IC EREN ENERJİ ELEK.ÜR.A.Ş. 600.000 4,005.9 2010-12-29 Zonguldak 42.0% 1,682.47 IPP IC EREN ENERJİ ELEK.ÜR.A.Ş. 600.000 4,005.9 2010-11-01 Zonguldak 42.0% 1,682.47 IPP IC EREN ENERJİ ELEK.ÜR.A.Ş. 160.000 1,068.2 2010-07-15 Zonguldak 41.0% 437.98 IPP IC İÇDAŞ ÇELİK 135.000 961.7 2009-10-13 Canakkale 35.0% 336.58 IPP IC İÇDAŞ ÇELİK 135.000 961.7 2009-07-24 Canakkale 35.0% 336.58 IC TOTAL 2,230.0 15,323.3 Average Efficiency 40.9% 6,268.9 This result is compatible with the information given by IEA (International Energy Agency), in which it was stated that supercritical pulverised (SCPC) is the dominant option for new coal fired power plants and maximum value for generating efficiency of SCPC plants is 46% (lower heating value, LHV), as of 2010 58. For the power plants using other types of solid fuels (hard coal, lignite, asphaltite, and waste materials incinerated), since there are no specific data that could be found, the efficiency factor is assumed as equal to that of imported coal, and the value that is nearest to the efficiency calculated for power plants using imported coal in the IPCC Default Efficiency Factors Table (Table 23), that is 41.5 %, was accepted as the efficiency factor. This is in line with the rule of conservativeness, since generally efficiency of other types of coal and other solid fuels is expected to be lower than that of imported coal, which is of higher quality. Also, since the share of other types of solid wastes are very small as compared to that of imported coal, their effect is minimal. For natural gas, the maximum value (60.0 %) was. For naphta, biogas, and liquefied petroleum gas (LPG) The efficiency factor is accepted as equal to natural gas. For liquid fuels except naphta, that is fuel oil and diesel oil, the efficiency factor is accepted as the maximum value in the table, 46 %, according to the rule of conservativeness. The results were put into the Equation (13) on page 22 of the Tool to calculate the Build Margin Emission Factor. Step 6: Calculate the combined margin emissions factor The calculation of the combined margin (CM) emission factor (EF grid,cm,y ) is done preferring the Weighted Average CM method, as indicated in paragraphs 77, 78, and 79 in the sub-section 6.6 on page 23 of the Tool. The weighted average combined margin emission factor calculation is done according to paragraphs 80 and 81 on pages 23 24 of the Tool, as follows: 80. The combined margin emissions factor is calculated as follows: 58 http://www.iea-etsap.org/web/e-techds/pdf/e01-coal-fired-power-gs-ad-gct.pdf, p. 1.

CDM Executive Board Page 47 EF grid, CM, y EFgrid, OM, y wom EFgrid, BM, y wbm Equation (14) Where: EF grid,bm,y EF grid,om,y w OM w BM = Build margin CO2 emission factor in year y (t CO2/MWh) = Operating margin CO2 emission factor in year y (t CO2/MWh) = Weighting of operating margin emissions factor (per cent) = Weighting of build margin emissions factor (per cent) 81. The following default values should be used for w OM and w BM : (a) Wind and solar power generation project activities: w OM = 0.75 and w BM = 0.25 (owing to their intermittent and non-dispatchable nature) for the first crediting period and for subsequent crediting periods; (b) All other projects: w OM = 0.5 and w BM = 0.5 for the first crediting period, and w OM = 0.25 and w BM = 0.75 for the second and third crediting period,6 unless otherwise specified in the approved methodology which refers to this tool. The details are in the Section B.6.3. Ex ante calculation of emission reductions. B.6.2. Data and parameters fixed ex ante Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment EG gross,y GWh Total quantity of gross electricity generation of power plants connected to the grid including low-cost/must-run power plants in year y for years in the 5-year period of [2007 2011]. Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details. Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. Calculation of baseline emissions. 59 http://www.turkstat.gov.tr/rip/rip.pdf 60 http://www.tuik.gov.tr/rip/temalar/4_3.html

CDM Executive Board Page 48 Data / Parameter Unit EG gross,i,y GWh Description Quantity of gross electricity generation of power plants using fuel type / utilizing primary energy source i connected to the grid including lowcost/must-run power plants in year y for years in the 5-year period of [2007 2011]. Source of data Value(s) applied Choice of data or Measurement methods and procedures Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. Purpose of data Additional comment Since power plant based data is unavailable, the amounts of generation for group of power plants using the same fuel type / utilizing the same primary energy source i were used. Calculation of baseline emissions. Data / Parameter EG,y Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment - GWh Total net quantity of electricity generation of power plants connected to the grid, not including low-cost/must-run power plants in year y for years in the 5-year period of [2007 2011]. Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. Calculation of baseline emissions.

CDM Executive Board Page 49 Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures EG i,y GWh Net quantity of electricity generation of power plants using fuel type i connected to the grid, not including low-cost/must-run power plants in year y for years in the 5-year period of [2007 2011]. Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. Purpose of data Additional comment - Since power plant based and fuel/primary energy source specific data is not available, net electricity generation of each group of power plants using the same fuel i for that year y was calculated applying the same net/gross electricity generation ratio for that year y to gross generation of each group of power plants using the same fuel i in that year y. Calculation of baseline emissions. Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment - EG import,y GWh Quantity of electricity imports in year y for years in the 5-year period of [2007 2011]. Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. Calculation of baseline emissions.

CDM Executive Board Page 50 Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment - FC i,y ton (liquid and solid fuels) / 10 3 m 3 (gaseous fuels) Amount of fuels consumed in thermal power plants in Turkey by fuel type i in year y for years in the 5-year period of [2007 2011]. Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. Calculation of baseline emissions. Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment NCV i,y TJ/Gg, GJ/ton Net calorific value of fuel type i consumed by thermal power plants in year y in the 5-year period of [2007 2011] Official data from TEIAS (Turkish Electricity Transmission Company), the responsible authority for the operation of Turkish National Grid. See Section B.6.3 and/or Appendix 4 for details Official data. According to the regulations regarding the Turkish Statistical Institute, the state organization responsible for the statistical affairs in the Republic of Turkey, TEIAS is the official source of data for energy 59,60. The net calorific values are calculated using the amount of fuels used 1 and the heating values of the fuels 31. Calculation of baseline emissions. In order for all the units of consumed fuels to be compatible with each other, the unit of natural gas consumed should be converted to mass units. Also, heating values given by TEIAS, which are expressed in [cal], must be converted into [J]. For this purpose, conversion factors given in International Energy Agency were used 33,34,35. Natural gas density was accepted as 0.692 kg/m 3, and 1 cal was assumed to be equal to 4.1868 J.

CDM Executive Board Page 51 Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment - EF CO2,i,y kg/tj Default CO 2 emission factors of fossil fuel type i for combustion. IPCC default values at the lower limit of the uncertainty at a 95 per cent confidence interval as provided in table 1.4 of Chapter1 of Vol. 2 (Energy) of the 2006 IPCC Guidelines on National GHG Inventories, pages 1.23 1.24 32. See Section B.6.1, B.6.3 and/or Appendix 4 for details. Country or project specific data are not available for power plants using fossil fuels in Turkey. Hence, IPCC default emission factors have been used according to the Tool (Section 7, page 29) and the UNFCCC CDM Guidance on IPCC Default Values 61. Calculation of baseline emissions. Data / Parameter Unit Description Source of data Value(s) applied Choice of data or Measurement methods and procedures Purpose of data Additional comment - η i,y Dimensionless (% ratio) Average net energy conversion efficiency of power units using fuel i in year y. For power plants using imported coal as fuel, the data given in presentation by Muzaffer Basaran in Panel about Coal-Fired Power Plants and Investment Models, in Middle East Technical University Alumni Association Visnelik Facility, on 23 February 2013 57 were used. For other types of fuels, the values in Table 1 in Appendix 1 of the Tool were applied. See Section B.6.1, B.6.3 and/or Appendix 4 for details. Power plant and/or fuel type specific of net energy conversion efficiencies are impossible or very hard to find. Hence, the data available for imported coal using power plants from a panel conducted at the alumni association of a technical university (Middle East Technical University) were used. For the other fuel types, default efficiency factors for power plants in Appendix 1 of the Tool were selected taking the conservativeness rule into account. Calculation of baseline emissions. 61 http://cdm.unfccc.int/reference/guidclarif/meth/meth_guid16_v01.pdf

CDM Executive Board Page 52 Data / Parameter Unit Description Source of data CAP BM Power Plant Name, Installed Capacity [MW], Electricity Generation [GWh], Commissioning Date [YYYY-MM-DD] Capacity additions forming the sample group of power units used to calculate the build margin. TEIAS (Turkish Electricity Transmission Company) Capacity Projection Reports and Ministry of Energy and Natural Resources of Republic of Turkey Energy Investment Data 50,51. Operational power plants at the end of 2011 were selected as the reference group 21. Value(s) applied See Section B.6.3 and Appendix 4. Choice of data or Measurement methods and procedures Purpose of data Additional comment - Annual electricity generation of the project electricity system AEG total was determined excluding power units registered as CDM project activities and capacity additions from retrofits of power plants. Since generation data for individual power plants are not available, but firm generation capacities of individual power plants are available, firm generation capacities were used as the actual generations 21. Every single commissioning of each power plant is assumed as a power unit. These power units are sorted by date from the newest to the oldest. The newest 5 power units, SET 5-units, their electricity generation AEG SET-5-units, and the group of power units that started to supply electricity to the grid most recently and that comprise 20 per cent of AEG total, SET 20 per cent, and their electricity generation AEG SET- 20 per cent were identified. Calculation of baseline emissions. B.6.3. Ex ante calculation of emission reductions a) Operating Margin Emission Factor Calculation: The calculation was performed according to the Option B of the Simple OM method of the Tool. Only grid connected power plants were included in the project electricity system. Ex-ante option was chosen, and a 3-year generation-weighted average, based on the most recent data available at the time of submission, was taken. The relevant reference period corresponds to the 3 year period of [2009 2011]. The gross electricity generations of these years by primary energy sources are as follows 62,63,64 : 62 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2011/uretim%20tuketim(22-45)/44.xls 63 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2010/front%20page%202010-çiçek%20kitap/uretim%20tuketim(22-45)/44.xls 64 http://www.teias.gov.tr/türkiyeelektrikistatistikleri/istatistik2009/41.xls

CDM Executive Board Page 53 Table 25. Gross Electricity Generations of Turkish Electricity System by Primary Energy Sources in Years [2009 2011] Gross Generations by Fuel Types and Primary Energy Resources in [2009-2011] (Unit: GWh) Primary Energy Resource or Fuel Type Years 2009 2010 2011 3-Year Total Hard Coal + Imported Coal + Asphaltite 16,595.6 19,104.3 27,347.5 63,047.4 Lignite 39,089.5 35,942.1 38,870.4 113,901.9 Total Coal 55,685.1 55,046.4 66,217.9 176,949.3 Fuel-Oil 4,439.8 2,143.8 900.5 7,484.1 Diesel Oil 345.8 4.3 3.1 353.2 LPG 0.4 0.0 0.0 0.4 Naphtha 17.6 31.9 0.0 49.5 Total Oil (Liquid Total) 4,803.5 2,180.0 903.6 7,887.2 Natural Gas 96,094.7 98,143.7 104,047.6 298,286.0 Renewables and Wastes 340.1 457.5 469.2 1,266.9 Thermal 156,923.4 155,827.6 171,638.3 484,389.4 Hydro + Geothermal + Wind Total 37,889.5 55,380.1 57,756.8 151,026.4 Hydro 35,958.4 51,795.5 52,338.6 140,092.5 Geothermal + Wind 1,931.1 3,584.6 5,418.2 10,933.9 Geothermal 435.7 668.2 694.3 1,798.3 Wind 1,495.4 2,916.4 4,723.9 9,135.6 General Total (Gross) 194,812.9 211,207.7 229,395.1 635,415.7 Net electricity generation is only available for the whole project electricity system, not for each fuel type or primary energy source 47 : Table 26. Gross and Net Electricity Generations of Turkish Electricity System in Years [2009 2011] Gross and Net Generations in [2009-2011] (Unit: GWh) Primary Energy Resource or Fuel Years Type 2009 2010 2011 3-Year Total General Total (Gross) 194,812.9 211,207.7 229,395.1 635,415.7 General Total (Net) 186,619.3 203,046.1 217,557.7 607,223.1 Net / Gross Ratio 95.79% 96.14% 94.84% 95.56% The corresponding net/gross ratio of each year was applied to gross generations of each primary energy source to find the net generation of group of power plants utilizing that primary energy source, with low-cost/must-run power plants excluded: Table 27. Net Electricity Generations of Turkish Electricity System by Primary Energy Sources, Excluding Low-Cost/Must-Run Power Plants, (Thermal Power Plants) in Years [2009 2011] Net Electricity Generation Excluding Years Low-Cost/Must-Run (Thermal Power Plants) (Unit: GWh) 2009 2010 2011 3-Year Total

CDM Executive Board Page 54 Hard Coal+Imported Coal+Asphaltite 15,897.6 18,366.0 25,936.3 60,199.9 Lignite 37,445.4 34,553.2 36,864.6 108,863.2 Fuel Oil 4,253.0 2,061.0 854.0 7,168.1 Diesel oil 331.3 4.1 2.9 338.3 LPG 0.4 0.0 0.0 0.4 Naphtha 16.8 30.7 0.0 47.5 Natural Gas 92,053.1 94,351.2 98,678.5 285,082.7 Renewables and Wastes 325.8 439.8 445.0 1,210.7 Turkey's Thermal Total 150,323.4 149,806.0 162,781.3 462,910.7 Fuel consumptions of thermal power plants were also taken from TEIAS statistics 1. The amount of natural gas was converted from volume to mass units using the density value of 0.692 kg/m 3, as explained in section B.6.1. Table 28. Fuel Consumption of Thermal Power Plants by Fuel Type, in Years [2009 2011] Fuel Consumption in Electricity Years Generation Excluding Low-Cost/Must- Run (Unit: Ton) 2009 2010 2011 3-Year Total Hard Coal+Imported Coal+Asphaltite 6,621,177.0 7,419,703.0 10,574,434.0 24,615,314.0 Lignite 63,620,518.0 56,689,392.0 61,507,310.0 181,817,220.0 Fuel Oil 1,594,321.0 891,782.0 531,608.0 3,017,711.0 Diesel oil 180,857.0 20,354.0 15,047.0 216,258.0 LPG 111.0 0.0 0.0 111.0 Naphtha 8,077.0 13,140.0 0.0 21,217.0 Natural Gas 14,515,664.6 15,072,939.7 15,779,535.9 45,368,140.2 Turkey's Thermal Total 86,540,725.6 80,107,310.7 88,407,934.9 255,055,971.2 Heating values of fuels consumed in power plants were also taken from the TEIAS statistics 31. These values were in [Tcal] units, and were converted into [TJ], using the ratio 1 cal = 4.1868 J, given by IEA 33,34,35. Table 29. Heating Values of Fuels Consumed in Thermal Power Plants in Turkey, in Years [2009 2011] Heating Values of Fuels Consumed in Years Thermal Power Plants (Unit: TJ) 2009 2010 2011 3-Year Total Hard Coal+Imported Coal+Asphaltite 147,081.2 165,573.3 241,022.6 553,677.2 Lignite 408,847.5 404,239.7 448,864.9 1,261,952.1 Fuel Oil 63,471.5 35,877.2 22,105.8 121,454.5 Diesel oil 7,662.8 877.1 649.3 9,189.1 LPG 5.2 0.0 0.0 5.2 Naphtha 352.5 440.2 0.0 792.7 Natural Gas 779,857.7 814,279.2 846,002.0 2,440,138.9 Turkey's Thermal Total 1,407,278.4 1,421,286.7 1,558,644.5 4,387,209.6 The corresponding net calorific values (NCV) were found as follows:

CDM Executive Board Page 55 Table 30. Net Calorific Values of Fuels Consumed in Thermal Power Plants in Turkey, in Years [2009 2011] Net Calorific Values of Fuels Years Consumed in Thermal Power Plants (Unit: TJ/Gg) 2009 2010 2011 Hard Coal+Imported Coal+Asphaltite 22.2 22.3 22.8 Lignite 6.4 7.1 7.3 Fuel Oil 39.8 40.2 41.6 Diesel oil 42.4 43.1 43.2 LPG 46.5 0.0 0.0 Naphtha 43.6 33.5 0.0 Natural Gas 53.7 54.0 53.6 Turkey's Thermal Total 16.3 17.7 17.6 Due to the absence of power-plant based or fuel based emission factor data, the lower limit of the 95 percent confidence intervals of IPCC default emission factor values were applied 32, and the emission factor for electricity imports were assumed as zero: Table 31. Emission Factors used in the Operating Margin Emission Factor Calculation. Table 1.4 Emission Factors by Fuel Type (IPCC Values) (kg/tj) Default CO 2 Emission Factors for Combustion (kg/tj) Default Lower Upper Hard Coal+Imported Coal+Asphaltite 94,600 89,500 99,700 Lignite 101,000 90,900 115,000 Fuel Oil 77,400 75,500 78,800 Diesel oil 74,100 72,600 74,800 LPG 63,100 61,600 65,600 Naphtha 73,300 69,300 76,300 Natural Gas 56,100 54,300 58,300 Import 0 0 0 The corresponding emissions and Operating Margin Emission Factors were calculated using the above values: Table 32. Operating Margin Emission Factor Calculation.

CDM Executive Board Page 56 Operating Margin Emission Factor Calculation CO 2 Emissions (ton) Years 2009 2010 2011 Hard Coal+Imported Coal+Asphaltite 13,163,770.74 14,818,807.99 21,571,526.82 Lignite 37,164,240.90 36,745,389.26 40,801,815.79 Fuel Oil 4,792,096.57 2,708,730.18 1,668,984.86 Diesel oil 556,318.57 63,674.50 47,138.38 LPG 317.74 0.00 0.00 Naphtha 24,429.94 30,502.68 0.00 Natural Gas 42,346,272.06 44,215,362.69 45,937,907.18 Import 0.00 0.00 0.00 Total Emission [ton] 98,047,446.52 98,582,467.30 110,027,373.03 Total Net Electricity Generation, excluding low-cost/must-run [GWh] 149,997.58 149,366.19 162,336.32 Yearly Emission Factor [tco 2/MWh] 0.654 0.660 0.678 2009-2011 Total Emissions [ton] 306,657,286.85 2009-2011 Total Net Electricity Gen. [GWh] 461,700.1 2009-2011 OMEF Calculation [tco 2/MWh] 0.664 As a result, the Operating Margin Emission Factor for the selected period was found to be EF grid,om, simple = 0.664 tco 2 /MWh. b) Build Margin Emission Factor Calculation: Option 1, ex ante based build margin emission factor calculation, was selected. Capacity additions from retrofits of power plants that could be identified are as follows: Table 33. Capacity additions from retrofits of power plants that could be identified in commissioned power units. Capacity Additions from Retrofit of Power Plants (As at the end 2011) No Fuel / Energy Source POWER PLANT NAME Installed Capacity MW Firm Generation Capacity (year 2012) GWh Commissioning Date Location (Province) Retrofit Type 1 NG AKBAŞLAR 3.960 30.06 2003-09-13 Bursa FS from FO to NG 2 NG AMYLUM NİŞASTA (Adana) 6.200 34.69 Adana FS from FO to NG 3 NG DENİZLİ ÇİMENTO 14.000 113.00 2006-05-04 Denizli FS from FO to NG 4 NG ISPARTA MENSUCAT 4.300 33.00 Isparta FS from FO to NG 5 NG PAKGIDA (Düzce-Köseköy) 4.800 38.26 Duzce FS from LPG to NG 6 NG PAKMAYA (Köseköy) 4.800 38.26 Kocaeli FS from LPG to NG 7 NG PAKMAYA (Köseköy) 2.100 16.74 2003-07-02 Kocaeli FS from LPG to NG 8 NG KAREGE ARGES 26.280 209.09 2003-07-30 Izmir FS from FO to NG GENERAL TOTAL 66.4 513.1 Abbreviations: FS: Fuel Switch, NG: Natural Gas, FO: Fuel Oil, LPG: Liquefied Petroleum Gas

CDM Executive Board Page 57 CDM project activities are identified as follows 21,52,53,54,55 : Table 34. CDM VER Projects in Turkey as at the end of 2011 No Fuel / Energy Source Power Plant Name Installed Capacity (MW) Location (Province) Commissioning Date (First) Standard Code / Number / Project ID 1 WS ITC-KA ENERJİ MAMAK 25.4 Ankara 2011-10-14 GS GS440 2 WS ITC-KA ENERJİ SİNCAN 5.7 Ankara 2011-04-08 GS GS675 3 WS ITC-KA ENERJİ KONYA (ASLIM BİYOKÜTLE) 5.7 Konya 2011-10-21 GS GS1016 4 WS ITC-KA ENERJİ ADANA (BİYOKÜTLE) 11.3 Adana 2011-10-06 GS GS715 5 WS ORTADOĞU ENERJİ (KÖMÜRCÜODA) 5.8 Istanbul 2009-07-15 GS GS707 6 WS BOLU BEL.ÇÖP (CEV MARMARA) 1.1 Bolu 2011-08-26 GS GS764 7 WS KAYSERİ KATI ATIK (HER EN.) 1.6 Kayseri 2011-11-01 GS GS1061 8 HE AKIM (CEVİZLİK HES) 91.4 Giresun 2010-05-28 VCS 753 9 HE ANADOLU ÇAKIRLAR 16.2 Artvin 2009-08-13 GS GS917 10 HE ASA EN.(KALE REG.) 9.6 Rize 2010-02-19 GS GS637 11 HE AYRANCILAR (MURADİYE ELEK.) 32.1 Van 2011-08-25 GS, VCS 12 HE CEYKAR BAĞIŞLI 29.6 Hakkari 2009-05-07 VCS 657 13 HE BEREKET (KOYULHİSAR) 42.0 Sivas 2009-06-12 VCS 713 14 HE BEYOBASI (SIRMA) 5.9 Aydin 2009-05-23 VCS 603 GS729, 577 15 HE BEYTEK(ÇATALOLUK HES) 9.5 K.Maras 2010-04-07 GS GS872 16 HE BULAM 7.0 Adiyaman 2010-08-10 GS GS642 17 HE BURÇBENDİ (AKKUR EN.) 27.3 Adiyaman 2010-11-04 VCS 419 18 HE CEVHER (ÖZCEVHER) 16.4 Trabzon 2011-01-17 GS GS688 19 HE CEYHAN HES (BERKMAN HES-ENOVA) 25.2 Osmaniye 2010-08-28 VCS 810 20 HE CEYHAN HES (OŞKAN HES-ENOVA) 23.9 Osmaniye 2010-06-03 VCS 810 21 HE ÇAKIT HES 20.2 Adana 2010-06-01 VCS 685 22 HE ÇALDERE ELEKTRİK DALAMAN MUĞLA 8.7 Mugla 2008-04-02 VCS 363 23 HE ÇAMLICA 27.6 Kayseri 2011-04-01 VCS 759 24 HE DAMLAPINAR(CENAY ELEK.) 16.4 Karaman 2010-07-08 VER+ 25 HE DARCA HES (BÜKOR EL.) 8.9 Bilecik 2011-05-26 GS GS887 26 HE DEĞİRMENÜSTÜ (KAHRAMANMARAŞ) 38.6 K.Maras 2009-04-16 VCS 565 27 HE EGEMEN 1 HES (ENERSİS ELEK.) 19.9 Bursa 2010-12-28 GS GS755 28 HE ELESTAŞ YAYLABEL 5.1 Isparta 2009-09-07 VCS 582 29 HE ELESTAŞ YAZI 1.1 Cankiri 2009-10-02 VCS 583 30 HE ERİKLİ-AKOCAK REG.(AK EN.) 82.5 Trabzon 2010-07-29 VCS 535 31 HE EŞEN-I (GÖLTAŞ) 60.0 Mugla 2011-04-24 VER+ 97-1 32 HE FEKE 2 (AKKUR EN.) 69.3 Adana 2010-12-24 VCS 534 33 HE FİLYOS YALNIZCA HES 14.4 Karabük 2009-09-16 GS GS618 34 HE GÜZELÇAY-I HES(İLK EN.) 8.1 Sinop 2010-11-11 GS GS711 35 HE HAMZALI HES (TURKON MNG ELEK.) 16.7 Kirikkale 2008-11-08 GS GS633 36 HE HASANLAR (DÜZCE) 4.7 Duzce 2011-12-02 GS GS831 37 HE HİDRO KONTROL (SELİMOĞLU HES) 8.8 Trabzon 2010-01-07 GS GS635 38 HE KALE HES 34.1 K.Maras 2010-06-16 VCS 893 39 HE KALEN ENER. (KALEN I-II) 31.3 Giresun 2009-06-19 VCS 932

CDM Executive Board Page 58 40 HE KALKANDERE-YOKUŞLU HES(AKIM EN.) 37.9 Rize 2011-01-28 VCS 905 41 HE KARASU I HES (İDEAL EN.) 3.8 Erzurum 2011-05-19 GS GS927 42 HE KARASU 4-2 HES (İDEAL EN.) 10.4 Erzincan 2011-11-24 GS GS928 43 HE KARASU 4-3 HES (İDEAL EN.) 4.6 Erzincan 2011-08-05 GS GS929 44 HE KARASU 5 HES (İDEAL EN.) 4.1 Erzincan 2011-08-03 GS GS929 45 HE KAR-EN KARADENİZ ELEK.(ARALIK HES) 12.4 Artvin 2010-04-30 GS GS663 46 HE KAYABÜKÜ HES (ELİTE ELEK.) 14.6 Bolu 2010-07-21 GS GS726 47 HE KIRAN HES (ARSAN EN.) 9.7 Giresun 2011-11-04 GS GS691 48 HE KOZDERE (ADO MAD.) 3.1 Antalya 2011-10-08 GS G434 49 HE KUMKÖY HES (KUMKÖY EN.) 17.5 Samsun 2011-02-23 VER+ 50 HE TGT EN. LAMAS III-IV 35.7 Mersin 2009-06-05 VCS 726 51 HE MARAŞ ENERJİ (FIRNIS) 7.2 K.Maras 2008-06-05 VER+ 52 HE MENGE (ENERJİ-SA) 44.7 Adana 2011-12-22 VCS 578 53 HE OTLUCA I HES (BEYOBASI) 37.5 Mersin 2011-04-07 VCS 755 54 HE OTLUCA II HES (BEYOBASI) 6.4 Mersin 2011-07-13 VCS 755 55 HE ÖZGÜR ELEKTR.AZMAK I 11.8 Mersin 2010-07-10 VCS 554 56 HE ÖZGÜR ELEKTR.AZMAK II 6.3 Mersin 2010-07-11 VCS 554 57 HE ÖZTAY GÜNAYŞE 8.3 Trabzon 2009-08-13 GS GS636 58 HE PAŞA HES(ÖZGÜR EL.) 8.7 Bolu 2010-06-11 GS GS681 59 HE REŞADİYE I HES(TURKON MNG EL. 15.7 Sivas 2010-11-26 GS GS643 60 HE REŞADİYE II HES(TURKON MNG EL. 26.1 Tokat 2010-09-17 GS GS644 61 HE REŞADİYE III HES(TURKON MNG EL. 22.3 Tokat 2009-11-11 GS GS645 62 HE SARAÇBENDİ (ÇAMLICA) 25.5 Sivas 2011-05-06 VCS 758 63 HE SAYAN (KAREL) 14.9 Osmaniye 2011-11-19 GS GS730 64 HE SEFAKÖY (PURE) 33.1 Kars 2011-10-12 VCS 747 65 HE SELEN EL.(KEPEZKAYA HES) 28.0 Karaman 2010-09-06 VER+ 66 HE SÖĞÜTLÜKAYA (POSOF HES) YENİGÜN EN. 6.1 Ardahan 2011-01-20 GS GS891 67 HE TEKTUĞ-KARGILIK 23.9 K.Maras 2005-04-24 VCS 264 68 HE TEKTUĞ-KALEALTI HES 15.0 Osmaniye 2006-11-30 VCS 111 69 HE TEKTUĞ-KEBENDERESİ 5.0 Elazig 2007-05-09 VCS 598 70 HE TEKTUĞ-ERKENEK 13.0 Adiyaman 2009-11-10 VCS 693 71 HE YAMAÇ HES (YAMAÇ ENERJİ ÜRETİM A.Ş.) 5.5 Osmaniye 2011-07-20 GS GS926 72 HE YEŞİLBAŞ 14.0 Sivas 2009-12-04 VCS 806 73 HE YAPISAN KARICA DARICA 110.3 Ordu 2011-07-26 VCS 506 74 HE YPM ALTINTEPE SUŞEHRİ HES 4.0 Sivas 2007-06-07 VCS 914 75 HE YPM BEYPINAR HES 3.6 Sivas 2007-06-07 VCS 914 76 HE YPM KONAK HES (SUŞEHRİ/SİVAS) 4.0 Sivas 2007-07-20 VCS 914 77 HE YPM GÖLOVA 1.1 Sivas 2009-06-10 VCS 914 78 HE YPM SEVİNDİK 5.7 Sivas 2009-06-09 VCS 914 79 HE ULUBAT KUVVET TÜN.(AK EN.) 100.0 Bursa 2010-10-22 VCS 536 80 WD ALİZE ENERJİ (ÇAMSEKİ) 20.8 Canakkale 2009-06-24 GS GS399 81 WD ALİZE ENERJİ (KELTEPE) 20.7 Balikesir 2010-04-28 GS GS437 82 WD ALİZE ENERJİ (SARIKAYA ŞARKÖY) 28.8 Tekirdag 2009-10-19 GS GS577 83 WD AK ENERJİ AYYILDIZ (BANDIRMA) 15.0 Balikesir 2009-07-23 GS GS634 84 WD AKDENİZ ELEK. MERSİN RES 33.0 Mersin 2010-03-19 GS GS753 85 WD AKRES (AKHİSAR RÜZGAR) 43.8 Manisa 2011-09-23 GS GS955 86 WD ANEMON ENERJİ (İNTEPE) 30.4 Canakkale 2007-11-22 GS GS347 87 WD ASMAKİNSAN (BANDIRMA-3 RES) 24.0 Balikesir 2010-03-26 GS GS683

CDM Executive Board Page 59 88 WD AYEN ENERJİ (AKBÜK) 31.5 Aydin 2009-04-03 GS GS436 89 WD AYVACIK (AYRES) 5.0 Canakkale 2011-10-23 GS GS956 90 WD BAKRAS ELEK.ŞENBÜK RES 15.0 Hatay 2010-04-22 GS GS733 91 WD BARES (BANDIRMA) 30.0 Balikesir 2011-08-11 GS, VER+ GS1072, 52-1 92 WD BELEN HATAY 36.0 Hatay 2010-09-02 GS GS390 93 WD BERGAMA RES (ALİAĞA RES) 90.0 Izmir 2010-06-16 GS GS735 94 WD BORASKO BANDIRMA 60.0 Balikesir 2010-06-30 GS GS744 95 WD BOREAS EN.(ENEZ RES) 15.0 Edirne 2010-04-09 GS GS702 96 WD ÇANAKKALE RES (ENERJİ-SA) 29.9 Canakkale 2011-05-06 GS GS906 97 WD ÇATALTEPE (ALİZE EN.) 16.0 Balikesir 2011-04-19 GS GS574 98 WD DOĞAL ENERJİ (BURGAZ) 14.9 Canakkale 2008-05-08 GS GS439 99 WD DENİZLİ ELEKT. (Karakurt-Akhisar) 10.8 Manisa 2007-05-28 VCS, VER+ 100 WD MARE MANASTIR 39.2 Izmir 2007-04-13 GS GS368 101 WD MAZI 3 30.0 Izmir 2010-06-18 GS GS388 102 WD KİLLİK RES (PEM EN.) 40.0 Tokat 2011-12-17 GS GS947 103 WD KORES KOCADAĞ 15.0 Izmir 2009-12-23 GS GS601 104 WD KUYUCAK (ALİZE ENER.) 25.6 Manisa 2010-12-09 GS GS576 105 WD ROTOR (OSMANİYE RES-GÖKÇEDAĞ RES) 135.0 Osmaniye 2010-10-15 GS GS474 106 WD BAKİ ELEKTRİK ŞAMLI RÜZGAR 114.0 Balikesir 2011-11-13 GS GS351 107 WD DATÇA RES 29.6 Mugla 2009-12-24 GS GS438 108 WD ERTÜRK ELEKT. (ÇATALCA) 60.0 Istanbul 2008-12-27 GS GS367 109 WD İNNORES ELEK. YUNTDAĞ 52.5 Izmir 2011-09-27 GS GS352 110 WD LODOS RES (TAŞOLUK)KEMERBURGAZ 24.0 Istanbul 2008-08-20 GS GS503 111 WD SARES (GARET ENER.) 22.5 Canakkale 2011-03-10 GS GS963 112 WD SAYALAR RÜZGAR (DOĞAL ENERJİ) 34.2 Manisa 2009-09-06 GS GS369 113 WD SEBENOBA (DENİZ ELEK.)SAMANDAĞ 30.0 Hatay 2010-03-12 VCS, VER+ 114 WD SEYİTALİ RES (DORUK EN.) 30.0 Izmir 2011-07-22 GS GS578 115 WD SOMA RES 116.1 Manisa 2011-12-09 GS GS398 116 WD SOMA RES (BİLGİN ELEK.) 90.0 Manisa 2010-11-11 GS GS655 117 WD SUSURLUK (ALANTEK EN.) 45.0 Balikesir 2011-05-20 GS GS854 118 WD ŞAH RES (GALATA WIND) 93.0 Balikesir 2011-07-29 GS GS905 119 WD TURGUTTEPE RES (SABAŞ ELEK.) 24.0 Aydin 2011-03-04 GS GS610 120 WD ÜTOPYA ELEKTRİK 30.0 Izmir 2010-09-03 GS GS672 121 WD ZİYARET RES 57.5 Hatay 2011-11-24 GS GS617 122 GT MENDERES JEOTERMAL 8.0 Aydin 2006-05-10 VCS 120 123 GT MENDERES JEOTERMAL DORA-2 9.5 Aydin 2010-03-26 GS GS445 124 GT TUZLA JEO. 7.5 Canakkale 2010-01-13 GS GS353 AYDIN GERMENCİK JEO.(MAREN 125 GT 20.0 Aydin 2011-11-11 GS GS861 MARAŞ) Abbreviations: WD: Wind, HE: Hydroelectric, WS: Waste, GT: Geothermal, GS: Gold Standard, VCS: Verified Carbon Standard 66 553 The remaining power units constitute the sample group used to calculate the build margin emission calculation. There are 639 power units in this group. Complete list of this sample group is in the Appendix 4 of this report. These power units in the sample group were sorted by date from the newest to the oldest. The newest 5 power units, SET 5-units, were identified as follows:

CDM Executive Board Page 60 Table 35. The set of five power units, excluding power units registered as CDM project activities, that started to supply electricity to the grid most recently (SET 5-units ) No Fuel / Energy Source POWER PLANT NAME Installed Capacit y (MW) Firm Generatio n Capacity (year 2012) (GWh) Commissionin g Date Location (Province) 1 NG TİRENDA TİRE 58.400 410.0 2011-12-30 Izmir 2 NG AKSA AKRİLİK KİMYA (İTH.KÖM.+D.G) 25.000 175.0 2011-12-30 Yalova 3 NG ALİAĞA Çakmaktepe Enerji 8.730 65.7 2011-12-29 Izmir 4 IC BEKİRLİ TES (İÇDAŞ ELEKT.) 600.000 4,320.0 2011-12-15 Canakkale 5 HE SARIKAVAK (ESER) 8.100 24.0 2011-11-25 Mersin Total 700.2 4,994.7 AEG SET-5-units 4,994,736 MWh Abbreviations: NG: Natural Gas, IC: Imported Coal, HE: Hydroelectric Hence, electricity generation of SET 5-units is found to be AEG SET-5-units = 4,994,736 MWh. The total generation of the sample group of power units used to calculate is AEG total = 256,636,382 MWh. 20 % of this value is AEG SET-=20 per cent = 51,327,276 MWh. When sorted from the newest to the oldest, the cumulative firm generation amount up to and including the 204 th power unit in the list, Aksa Enerji (Antalya) Natural Gas Power Plant, with an installed capacity of 46,7 MW and firm generation capacity of 324.9 GWh, which was commissioned on 29/12/2008, gives us an firm generation amount of 51,589,558 MWh, and satisfies the condition of SET 20 per cent. Hence electricity generation of SET 20 per cent is found to be AEG SET- 20 per cent = 51,589,558 MWh. Since AEG SET- 20 per cent > AEG SET-5-units, and none of the power units in the SET 20 per cent started to supply electricity to the grid more than 10 years ago, it was assumed that SET sample = SET 20 per cent. The generation distribution of SET sample by primary energy sources is as follows: Table 36. The distribution of sample group used to calculate the build margin (SET sample ) by primary energy sources (fuels consumed) Energy Source / Fuel Installed Capacity (MW) Firm Generation Capacity (year 2012) (GWh) Asphaltite 135.0 945.0 Biogas 0.5 3.7 Diesel Oil 0.0 0.0 Fuel Oil 142.3 967.8 Geothermal 47.4 313.0 Hard Coal 0.0 0.0 Hydroelectric 1,866.2 3,384.5 Imported Coal 2,230.0 15,323.3 Lignite 24.4 147.0

CDM Executive Board Page 61 Liquefied Petroleum Gas 0.0 0.0 Natural Gas 4,053.7 30,079.7 Naphta 49.0 277.9 Wind 0.0 0.0 Waste 19.8 147.7 Total 8,568.3 51,589.6 These generation values were put into the formulation as explained in the section B.6.1., and the Build margin emission factor was calculated as shown in the following table: Table 37. Build Margin Emission Factor Calculation Energy Source / Fuel Firm Generation Capacity (year 2012) (GWh) Assumed Emission Factor (kg/tj) Assumed Default Efficiency (%) Calculated Emission Factor ((tco2/mwh) Emission (ton) Asphaltite 945.0 89,500 41.5% 0.776 733,684.3 Biogas 3.7 46,200 60.0% 0.277 1,025.6 Diesel Oil 0.0 72,600 46.0% 0.568 0.0 Fuel Oil 967.8 75,500 46.0% 0.591 571,857.5 Geothermal 313.0 0 0.0% 0.000 0.0 Hard Coal 0.0 92,800 41.5% 0.805 0.0 Hydroelectric 3,384.5 0 0.0% 0.000 0.0 Imported Coal 15,323.3 89,500 40.9% 0.788 12,071,339.9 Lignite 147.0 90,900 41.5% 0.789 115,913.9 Liquefied Petroleum Gas 0.0 61,600 60.0% 0.370 0.0 Natural Gas 30,079.7 54,300 60.0% 0.326 9,799,962.8 Naphta 277.9 69,300 60.0% 0.416 115,545.0 Wind 0.0 0 0.0% 0.000 0.0 Waste 147.7 73,300 41.5% 0.636 93,894.7 Total / Overall 51,589.6 0.456 23,503,223.7 The calculated Build Margin Emission Factor is EF grid,bm,y = 0.456 tco 2 /MWh. c) Combined Margin Emission Factor Calculation: Combined Margin Emission Factor calculation was done according to the tool as explained the section B.6.1., by using Weighted Average CM method, with weightings w OM = 0.75 and w BM = 0.25, since the project activity is a wind farm: EFgrid, CM, y EFgrid, OM, y wom EFgrid, BM, y wbm Equation (14) EF grid,cm,y = 0.664 * 0.75 + 0.456 * 0.25 = 0.612

CDM Executive Board Page 62 The Combined Margin Emission Factor is found to be EF grid,cm,y = 0.612 tco 2 /MWh. d) Emission Reduction Calculation: Emission reduction calculation for the first crediting period was done according to the Methodology, as indicated in section B.6.1., as follows: ER y = BE y PE y LE y Where: ER y BE y PE y LE y = Emission reductions in year y (t CO 2 /yr) = Baseline emissions in year y (t CO 2 /yr) = Project emissions in year y (t CO 2 /yr) = Leakage emissions year y (t CO 2 /yr) Since no leakage emissions are considered by the Methodology, and the project emissions are assumed as zero as explained in the section B.6.1., we found that the emission reductions is equal to the baseline emissions. ER y = BE y Baseline emissions are calculated using the formulation indicated on page 8 of the Methodology: Baseline emissions Baseline emissions include only CO 2 emissions from electricity generation in fossil fuel fired power plants that are displaced due to the project activity. The methodology assumes that all project electricity generation above baseline levels would have been generated by existing grid-connected power plants and the addition of new grid-connected power plants. The baseline emissions are to be calculated as follows: BE y EGPJ, y * EFgrid, CM, y (4) Where: BE = Baseline emissions in year y (tco 2 /yr) y EG PJ, = Quantity of net electricity generation that is produced and fed into the grid as a result y of the implementation of the CDM project activity in year y (MWh/yr) EF = Combined margin CO 2 emission factor for grid connected power generation in year y grid, CM, y calculated using the latest version of the Tool to calculate the emission factor for an electricity system (tco 2 /MWh) Since the project activity is a greenfield renewable energy power plant, the net electricity generation of the project activity is calculated according to the rule explained on page 8 9 of the Methodology: Calculation of EG PJ,y The calculation of EG PJ,y is different for: (a) greenfield plants, (b) retrofits and replacements; and (c) capacity additions. These cases are described next.

CDM Executive Board Page 63 (a) Greenfield renewable energy power plants If the project activity is the installation of a new grid-connected renewable power plant/unit at a site where no renewable power plant was operated prior to the implementation of the project activity, then: EG EG (5) PJ, y facility, y Where: EG = Quantity of net electricity generation that is produced and fed into the grid as a result PJ,y of the implementation of the CDM project activity in year y (MWh/yr) EG = Quantity of net electricity generation supplied by the project plant/unit to the grid in facility, y year y (MWh/yr) The net annual electricity generation of the project is calculated as EG facility,y = 194,003 MWh, as explained in section B.5. The details of this calculation are in both Emission Reduction Calculation and Investment Analysis spreadsheets as annexes to PDD. The baseline emission is found as: BE y = EG PJ,y * EF grid,cm,y = 194,003 * 0.612 = 118,737 tco 2 /yr. Hence, the emission reductions is ER y = 118,737 tco 2 /yr. For the first year of the crediting period (2012), the net average electricity generation is found to be 145,546 MWh. Hence for 2012, the emission reductions is ER 2012 = 89,079 tco 2. For the last year of the crediting period (2019), the net average electricity generation is found to be 39,864 MWh. Hence for 2019, the emission reductions is ER 2019 = 24,398 tco 2. Total amount of emission reductions for the first crediting period is 825,899 tco 2. Annual average over the first crediting period is calculated as 117,986 tco 2 /yr. This value is lower than the estimated amount of annual average GHG emission reductions, due to the partial commissionings in the first year, causing a lower amount of net electricity generation than the other years. The details of the emission factor and emission reduction calculations can be found in the emission reduction calculation spreadsheet as an annex to PDD.

CDM Executive Board Page 64 B.6.4. Summary of ex ante estimates of emission reductions Year Baseline emissions (t CO 2 e) Project emissions (t CO 2 e) Leakage (t CO 2 e) 2012 89,079 0 0 89,079 2013 118,737 0 0 118,737 2014 118,737 0 0 118,737 2015 118,737 0 0 118,737 2016 118,737 0 0 118,737 2017 118,737 0 0 118,737 2018 118,737 0 0 118,737 2019 24,398 0 0 24,398 Total 825,899 0 0 825,899 Total number of 7 years crediting years Annual average over the crediting period 117,986 0 0 117,986 Emission reductions (t CO 2 e)

CDM Executive Board Page 65 B.7. Monitoring plan B.7.1. Data and parameters to be monitored Data / Parameter Unit Description Source of data Value(s) applied Measurement methods and procedures EG facility,y MWh/yr Quantity of net electricity generation supplied by the project plant/unit to the grid in year y. Main source is the data from the web site of PMUM (Market Financial Settlement Centre) or EPIAS (Energy Markets Operation Company, which will replace PMUM according to the new Electricity Market Law in Turkey) 65 or any other equivalent state authority responsible for the operation of national electricity market in Turkey, in case it is enforced by the law before the end of the first crediting period. These data is based on the automatic meter reading from the electricity meters of the project activity, which is performed by TEIAS. This will be the preferred data. Auxiliary sources will be the monthly electricity protocols signed by TEIAS officials or electricity sales invoices. These will be used as confirmative and supportive documents, if necessary. 194,003 MWh/yr There are two groups of electricity meters for two groups of turbines, as indicated in the Section B.3 about the project boundary. Each group of electricity meters consists of a main meter and a backup meter. The amount of net electricity generation supplied by the project to the grid will be calculated by subtracting the amount of electricity drawn from the grid from the amount fed into the grid for each main electricity meter, and then adding net electricity generation amount for two main meters. 65 http://www.resmigazete.gov.tr/eskiler/2013/03/20130330-14.htm

CDM Executive Board Page 66 Monitoring frequency QA/QC procedures Unless otherwise enforced by the law, or stated in the monitoring reports, the monitoring will be done on a monthly basis. TEIAS is responsible for the electricity meter measurements and testing and control of electricity meters according to Communiqué on Meters to be used in the Electricity Market 66, and other related legislation. TEIAS performs annual periodic tests on every electricity meter, and the meters are sealed after each test, according to the System Usage Agreement made between the project proponent and TEIAS 67. These seals can only be broken and re-sealed only by TEIAS authorised personnel. Apart from the annual tests, the companies producing or importing the electricity meters are required to guarantee the accuracy and calibration of the meters 66. The data of PMUM (EPIAS, etc.) uses the electricity measurement data of TEIAS. This data is reliable since it is only accessible to project owner apart from PMUM (EPIAS, etc.), and used for invoicing purposes. Purpose of data Additional comment The data of the SCADA system installed within the project activity can also be used to cross-check the measurements of the electricity meters. Calculation of baseline emissions The electricity measurements are used for billing and strictly checked by project owner and TEIAS. Also, according to the Section III about Monitoring Methodology of ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0, all data collected as part of monitoring will be archived electronically and be kept at least two years after the end of the last crediting period. B.7.2. Sampling plan There will be no sampling procedures and all the data related with the electricity measurements will be used for monitoring purposes. B.7.3. Other elements of monitoring plan Operational and Management Structure Monitoring will be done according to ACM0002: Consolidated baseline methodology for gridconnected electricity generation from renewable sources --- Version 13.0.0. Electricity meters are located at the points indicated in the figure regarding the project boundary and simplified one-line single diagram of the project activity in the Section B.3 about the project boundary. At the end of each month, the data about the electricity measurements from PMUM (EPIAS, etc.) will be collected from the official web site after it has become definite. This data will be copied to spreadsheets 66 http://www.epdk.org.tr/documents/elektrik/mevzuat/teblig/elektrik/sayaclar_hakkinda/elk_tblg_sayaclar.doc 67 http://eud.teias.gov.tr/skam/skaornek.pdf

CDM Executive Board Page 67 to make the calculations easier. The web pages containing the relevant data will be saved as screenshot s and/or in suitable file formats and be kept for future reference. The monthly electricity meter reading protocols signed by authorised TEIAS officials will also be kept, if these are available. This will be done monthly. The expected verification period is one year. At the end of each verification period, all the documents collected monthly will be compiled and an emission reduction calculation spreadsheet will be prepared to show the final results of the emission reductions of the corresponding verification period. This spreadsheet and documents about electricity generation and the electricity meter readings will be sent to verifying DOE along with the monitoring report of the corresponding verification period. Responsibilities and Institutional Arrangements for Data Collection and Archiving Data collection and archiving will be under the responsibility of the project proponent. Power plant personnel will send the monthly electricity meter reading protocols and other relevant supportive documents, if any, to project proponent company headquarters. Power plant personnel will also give support and help during the site visits of validation, verification and other similar related processes. The data collection, archiving and communication with the DOEs will be done by the responsible personnel in the project proponent company headquarters. SECTION C. Duration and crediting period C.1. Duration of project activity C.1.1. Start date of project activity According to the Glossary of CDM terms 68 the start date of a project activity is defined as follows: In the context of a CDM project activity or CPA, the earliest date at which either the implementation or construction or real action of a CDM project activity or CPA begins. In the context of a CDM PoA, the date on which the coordinating/managing entity officially notifies the secretariat and the DNA of their intention to seek the CDM status or the date of publication of the PoA-DD for global stakeholder consultation in accordance with the relevant CDM rules and requirements. Along with this explanation, the start date of the construction the date at which the building site was handed over to the contractor company, was assumed as the start date of the project activity. Therefore, the start date of the project activity is 19/07/2011. C.1.2. Expected operational lifetime of project activity 20 years C.2. Crediting period of project activity C.2.1. Type of crediting period Renewable, first crediting period. C.2.2. Start date of crediting period 16/03/2012 68 http://cdm.unfccc.int/reference/guidclarif/glos_cdm.pdf

CDM Executive Board Page 68 C.2.3. Length of crediting period 7 years, 0 months. SECTION D. Environmental impacts D.1. Analysis of environmental impacts According to the Environmental Impact Assessment Regulation 69 the project activity is exempt from the environmental impact assessment. This is also certified by the exemption decisions granted by the responsible state authorities 70. However, considering that an environmental impact assessment study will ease the credit and emission reduction related affairs, the project proponent had an accredited consultant company prepare an environmental study. As a result, two environmental impact assessment reports, one for the project site, and one for the energy transmission line, have been prepared 71. According to these reports, the project is found to be compatible with regulations related with the environmental impact assessment, and no harmful effects to the environment could be found. The details are in the referred EIA reports. D.2. Environmental impact assessment No environmental impact assessment is required. In addition, the results of the voluntary environmental impact assessment study indicate that the project activity has minimal, if any, effects on the environment. Further information regarding various aspects of environmental impact assessment study can be found in the EIA reports. SECTION E. Local stakeholder consultation E.1. Solicitation of comments from local stakeholders Since the project activity is intended to be developed as a Gold Standard project, a thorough and detailed local stakeholder consultation process has been conducted. A Local Stakeholder Consultation meeting was held on 16/06/2011 in Yahyalı district of Kayseri province, after a comprehensive invitation process. Detailed information can be found in the Local Stakeholder Consultation Report and the Gold Standard Passport of the project. E.2. Summary of comments received In general, the comments were positive. No significant concerns about the probable negative effects of the project were raised during the meeting. Detailed information can be found in the Local Stakeholder Consultation Report and the Gold Standard Passport of the project. E.3. Report on consideration of comments received Please refer to Local Stakeholder Consultation Report and the Gold Standard Passport of the project for detailed information about this issue. 69 http://mevzuat.basbakanlik.gov.tr/metin.aspx?mevzuatkod=7.5.12256&sourcexmlsearch=&mevzuatiliski=0 70 These decisions have been uploaded to the registry site and are available for the DOE. There are three decisions; two for the project site (a main and a revised one), and one for the energy transmission line. 71 Both of these two EIA reports have been uploaded to the registry site and are available for the DOE.

CDM Executive Board Page 69 SECTION F. Approval and authorization Not available. - - - - -

CDM Executive Board Page 70 Appendix 1: Contact information of project participants Organization name Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A.S. Street/P.O. Box Hulya Sokak No: 37, G.O.P. Building City Ankara State/Region Postcode 06700 Country Turkey Telephone +90 312 445 04 64 Fax +90 312 445 05 02 E-mail ayen@ayen.com.tr Website http://www.ayen.com.tr Contact person Hakan Demir Title Salutation Mr. Last name Demir Middle name First name Hakan Department Mobile Direct fax Direct tel. +90 312 445 04 64 Extension: 306 Personal e-mail hakand@ayen.com.tr Appendix 2: Affirmation regarding public funding The project does not obtain any public funding. Appendix 3: Applicability of selected methodology Not available.

CDM Executive Board Page 71 Appendix 4: Further background information on ex ante calculation of emission reductions Power Plants Used to Calculate the Build Margin Emission Reduction Sorted by Commissioning Date from the Newest to the Oldest (The System at the End of 2011 with CDM-VER Projects and Capacity Additions from Retrofits of Power Plants Removed) No Fuel / Energy Source POWER PLANT NAME Installed Capacity (MW) Firm Generation Capacity (year 2012) (GWh) Commissioning Date Location (Province) 1 NG TİRENDA TİRE 58.400 410.0 2011-12-30 Izmir 2 NG AKSA AKRİLİK KİMYA (İTH.KÖM.+D.G) 25.000 175.0 2011-12-30 Yalova 3 NG ALİAĞA Çakmaktepe Enerji 8.730 65.7 2011-12-29 Izmir 4 IC BEKİRLİ TES (İÇDAŞ ELEKT.) 600.000 4,320.0 2011-12-15 Canakkale 5 HE SARIKAVAK (ESER) 8.100 24.0 2011-11-25 Mersin 6 FO MARDİN-KIZILTEPE(AKSA EN.) 32.100 225.0 2011-11-18 Mardin 7 HE ÇUKURÇAYI HES (AYDEMİR) 1.800 4.0 2011-11-03 Isparta 8 NG ODAŞ DOĞAL GAZ 55.000 415.0 2011-10-28 Sanliurfa 9 HE MURATLI HES (ARMAHES ELEK.) 26.700 55.0 2011-10-27 Sivas 10 NG TEKİRDAĞ TEKS.(NİL ÖRME) 2.700 21.0 2011-10-25 Tekirdag 11 NG SARAY HALI A.Ş. 4.300 33.0 2011-10-15 Kayseri 12 HE TEFEN HES (AKSU) 11.000 26.7 2011-10-13 Zonguldak 13 HE YEDİGÖL REG. VE HES (YEDİGÖL HES) 21.900 42.0 2011-10-13 Erzurum 14 NG AKSA ENERJİ (Antalya) 190.000 1,321.7 2011-10-07 Antalya 15 NG GOREN-1 (GAZİANTEP ORG.SAN.) 48.700 277.0 2011-09-30 Gaziantep 16 HE ÇANAKÇI HES (CAN EN.) 4.633 11.0 2011-09-29 Trabzon 17 NG AKSA ENERJİ (Antalya) 110.000 765.2 2011-09-17 Antalya 18 HE BOĞUNTU (BEYOBASI EN.ÜR.) 3.800 10.0 2011-09-16 Mersin 19 HE POYRAZ HES(YEŞİL EN.) 2.700 6.0 2011-09-16 K.Maras 20 NG BOSEN (Bursa San.) 93.000 698.0 2011-09-10 Bursa 21 HE ÇANAKÇI HES (CAN EN.) 4.633 11.0 2011-08-25 Trabzon 22 WS CEV EN.(GAZİANTEP ÇÖP) 4.524 29.6 2011-08-24 Gaziantep 23 HE ÇAMLIKAYA 2.824 3.7 2011-08-11 Trabzon 24 NG GORDİON AVM (REDEVCO ÜÇ ) 2.000 15.0 2011-08-05 Ankara 25 HE BALKONDU I HES (BTA ELEK.) 9.200 20.0 2011-08-05 Trabzon 26 HE KORUKÖY HES (AKAR EN.) 3.000 13.0 2011-08-05 Adiyaman 27 NG LOKMAN HEKİM ENGÜRÜ(SİNCAN) 0.500 4.0 2011-07-29 Ankara 28 NG ŞANLIURFA OSB (RASA EN.) 116.800 800.0 2011-07-26 Sanliurfa 29 NG HASIRCI TEKSTİL TİC. VE SAN. 2.000 15.0 2011-07-16 Gaziantep 30 NG KNAUF İNŞ. VE YAPI ELEMANLARI 1.600 12.0 2011-07-15 Ankara 31 NG MANİSA O.S.B. 43.500 347.8 2011-07-13 Manisa 32 HE TUZTAŞI HES (GÜRÜZ ELEK. ÜR. LTD.ŞTİ.) 1.600 6.0 2011-07-04 Sivas 33 NG ALİAĞA Çakmaktepe Enerji 130.950 986.0 2011-07-01 Izmir 34 HE KÖYOBASI HES (ŞİRİKOĞLU ELEK.) 1.100 3.0 2011-06-30 K.Maras 35 HE YAŞIL HES (YAŞIL ENERJİ EL. ÜRETİM A.Ş.) 2.276 4.8 2011-06-29 K.Maras 36 NG POLYPLEX EUROPA 3.904 30.7 2011-06-24 Tekirdag 37 HE ÜZÜMLÜ HES (AKGÜN EN. ÜR. VE TİC. A.Ş.) 11.400 23.0 2011-06-23 Erzincan 38 NG ALDAŞ ALTYAPI YÖN. 2.000 15.0 2011-06-15 Antalya 39 HE GÖKMEN REG. (SU-GÜCÜ ELEK.) 2.900 8.0 2011-06-15 Yozgat

CDM Executive Board Page 72 40 HE TEFEN HES (AKSU) 22.000 53.3 2011-06-10 Zonguldak 41 HE KARASU II HES (İDEAL EN.) 3.100 8.0 2011-06-03 Erzurum 42 HE ÖREN REG.(ÇELİKLER) 6.600 16.0 2011-05-26 Giresun 43 HE İNCİRLİ REG.(LASKAR EN.) 25.200 71.0 2011-05-25 Rize 44 HE YAŞIL HES (YAŞIL ENERJİ EL. ÜRETİM A.Ş.) 1.518 3.2 2011-05-20 K.Maras 45 NG ZORLU ENERJİ (B.Karıştıran) 7.200 54.1 2011-05-14 Kirklareli 46 HE KESME REG.(KIVANÇ EN.) 2.305 4.5 2011-04-22 K.Maras 47 HE YAPRAK II HES (NİSAN EL. ENERJİ) 5.400 10.5 2011-04-22 Amasya 48 HE KESME REG.(KIVANÇ EN.) 2.305 4.5 2011-04-14 K.Maras 49 HE ALKUMRU BARAJI VE HES(LİMAK) 87.090 156.0 2011-04-12 Siirt 50 NG GLOBAL ENERJİ (PELİTLİK) 4.000 29.9 2011-04-08 Tekirdag 51 HE KAZANKAYA REG.İNCESU HES(AKSA) 15.000 27.0 2011-04-08 Çorum 52 HE YAPRAK II HES (NİSAN EL. ENERJİ) 5.400 10.5 2011-04-03 Amasya 53 NG CENGİZ ENERJİ (Tekkeköy/SAMSUN) 35.000 281.3 2011-03-30 Samsun 54 NG BOYTEKS TEKS. 8.600 67.0 2011-03-19 Kayseri 55 HE HACININOĞLU HES (ENERJİ-SA) 71.140 102.0 2011-03-17 K.Maras 56 HE NARİNKALE HES (EBD EN.) 30.400 55.4 2011-03-17 Kars 57 HE ALKUMRU BARAJI VE HES(LİMAK) 174.180 312.0 2011-03-10 Siirt 58 NG GÜLLE ENTEGRE (Çorlu) 3.904 18.0 2011-03-04 Tekirdag 59 HE KULP I HES (YILDIZLAR EN.) 22.900 44.0 2011-03-04 Diyarbakir 60 HE DURU 2 REG.(DURUCASU EL.) 4.500 13.0 2011-02-25 Amasya 61 HE ÇAKIRMAN (YUSAKA EN.) 7.000 15.0 2011-02-19 Erzincan 62 NG TÜPRAŞ (Orta Anadolu-Kırıkkale) 12.000 84.8 2011-02-04 Kirikkale 63 HE HACININOĞLU HES (ENERJİ-SA) 71.140 102.0 2011-02-03 K.Maras 64 NG İSTANBUL SABİHA GÖKÇEN HAV. 4.000 32.0 2011-01-31 Istanbul 65 NG HG ENERJİ 52.400 366.0 2011-01-27 Kutahya 66 HE YEDİGÖZE HES 155.330 134.0 2011-01-26 Adana 67 NG FRAPORT İÇ İÇTAŞ ANTALYA HAV. 8.000 64.0 2011-01-24 Antalya 68 HE BAYRAMHACILI (SENERJİ EN.) 47.000 95.0 2011-01-20 Nevsehir 69 HE AKSU REG.(KALEN EN.) 5.200 12.0 2011-01-12 Giresun 70 HE ÇEŞMEBAŞI (GİMAK) 8.200 17.0 2011-01-12 Ankara 71 NG INTERNATIONAL HOSPITAL (İstanbul) 0.800 6.0 2010-12-31 Istanbul 72 NG RASA ENERJİ (VAN) 10.124 64.4 2010-12-29 Van 73 IC EREN ENERJİ ELEK.ÜR.A.Ş. 600.000 4,005.9 2010-12-29 Zonguldak 74 NG ALARKO ALTEK 21.890 151.4 2010-12-18 Kirklareli 75 NG POLYPLEX EUROPA 7.808 61.3 2010-12-16 Tekirdag 76 FO TÜPRAŞ (İzmit-Yarımca) 40.000 258.8 2010-12-15 Kocaeli 77 HE UMUT III HES(NİSAN EL.) 12.000 15.0 2010-12-13 Ordu 78 NG SÖNMEZ ELEKTRİK 2.564 19.8 2010-12-07 Usak 79 HE YEDİGÖZE HES 155.330 134.0 2010-12-02 Adana 80 BG FRİTOLEY GIDA 0.330 2.5 2010-11-26 Kocaeli 81 NG ALİAĞA Çakmaktepe Enerji 69.840 525.9 2010-11-26 Izmir 82 NG MARMARA PAMUK 26.190 203.6 2010-11-25 Tekirdag 83 HE MURGUL BAKIR 19.602 31.5 2010-11-11 Artvin 84 HE KARADENİZ ELEK.(UZUNDERE I HES) 31.076 46.5 2010-11-07 Rize 85 IC EREN ENERJİ ELEK.ÜR.A.Ş. 600.000 4,005.9 2010-11-01 Zonguldak 86 HE SABUNSUYU II HES (ANG EN.) 7.400 12.0 2010-10-28 Osmaniye 87 HE KAHTA I HES(ERDEMYILDIZ ELEK.) 7.100 20.0 2010-10-14 Adiyaman 88 NG ENERJİ-SA (Bandırma) 930.800 7,540.0 2010-10-07 Balikesir

CDM Executive Board Page 73 89 NG UĞUR ENERJİ (TEKİRDAĞ) 12.000 100.9 2010-10-07 Tekirdag 90 HE ERENKÖY REG.(TÜRKERLER) 21.500 49.0 2010-10-07 Artvin 91 HE KAHRAMAN REG.(KATIRCIOĞLU ELEK.) 1.400 3.0 2010-09-30 Giresun 92 HE NARİNKALE HES (EBD EN.) 3.100 5.6 2010-09-30 Kars 93 FO KIRKA BORAKS (Kırka) 10.000 65.9 2010-09-29 Eskisehir 94 HE KOZAN HES (SER-ER EN.) 4.000 5.0 2010-09-21 Adana 95 HE TEKTUĞ-ANDIRIN 40.500 60.0 2010-09-03 K.Maras 96 HE KARŞIYAKA HES (AKUA EN.) 1.600 5.0 2010-08-28 Gaziantep 97 NG SÖNMEZ ELEKTRİK 33.242 256.2 2010-08-26 Usak 98 HE GÜDÜL I (YAŞAM EN.) 2.400 8.0 2010-08-25 Malatya 99 NG KURTOĞLU BAKIR KURŞUN 1.600 12.0 2010-08-19 Tekirdag 100 NG CAN ENERJİ ELEK. ÜR.AŞ.(TEKİRDAĞ) 29.100 203.0 2010-08-19 Tekirdag 101 NG BİNATOM ELEKTRİK ÜRT. A.Ş. 2.000 13.0 2010-08-17 Kutahya 102 NG KESKİNOĞLU TAVUKÇULUK 3.500 25.0 2010-08-11 Manisa 103 HE GÖK HES 10.000 24.0 2010-08-06 Mersin 104 NG CENGİZ ENERJİ (Tekkeköy/SAMSUN) 101.950 819.4 2010-07-31 Samsun 105 NG RB KARESİ TEKS. (BURSA) 8.600 65.0 2010-07-23 Bursa 106 NG FLOKSER TEKSTİL (ÇERKEZKÖY) 5.200 42.0 2010-07-17 Tekirdag 107 IC EREN ENERJİ ELEK.ÜR.A.Ş. 160.000 1,068.2 2010-07-15 Zonguldak 108 HE YAVUZ HES (MASAT EN.) 22.500 47.0 2010-07-14 Amasya 109 HE KİRPİLİK HES (ÖZGÜR ELEK.) 6.200 13.0 2010-07-11 Mersin 110 NG ALARKO ALTEK 60.100 415.6 2010-07-10 Kirklareli 111 HE DİM HES (DİLER ELEK.) 38.300 70.0 2010-07-08 Antalya 112 HE DİNAR HES (ELDA ELEK.) 4.400 9.0 2010-07-03 Tunceli 113 NG AKSA ENERJİ (Antalya) 25.000 173.9 2010-07-01 Antalya 114 HE ÇAMLIKAYA 5.648 7.3 2010-06-30 Trabzon 115 NG UĞUR ENERJİ (TEKİRDAĞ) 48.200 405.1 2010-06-21 Tekirdag 116 HE ERENLER REG.(BME BİRLEŞİK EN.) 45.000 48.0 2010-06-04 Artvin 117 HE KARADENİZ ELEK.(UZUNDERE I HES) 31.076 46.5 2010-05-27 Rize 118 NG CENGİZ ENERJİ (Tekkeköy/SAMSUN) 101.950 819.4 2010-05-22 Samsun 119 NG ERDEMİR 78.400 473.3 2010-05-21 Zonguldak 120 HE BİRİM (ERFELEK HES) 3.225 5.5 2010-05-14 Sinop 121 NT ATAER ENERJİ (EBSO) 49.000 277.9 2010-05-05 Izmir 122 NG YILDIZ ENTEGRE 12.368 92.7 2010-04-22 Kocaeli 123 BG FRİTOLEY GIDA 0.065 0.5 2010-04-21 Kocaeli 124 HE FIRTINA ELEK.(SÜMER HES) 21.600 39.0 2010-04-16 Giresun 125 HE NİSAN EN.(BAŞAK HES) 6.900 12.0 2010-04-09 Kastamonu 126 HE BİRİM (ERFELEK HES) 3.225 5.5 2010-04-03 Sinop 127 HE NURYOL EN.(DEFNE HES) 7.200 13.0 2010-03-26 Duzce 128 NG AKSA ENERJİ (Antalya) 25.000 173.9 2010-03-20 Antalya 129 HE DOĞUBAY ELEK.(SARIMEHMET HES) 3.100 6.0 2010-03-11 Van 130 NG RASA ENERJİ (VAN) 26.190 166.6 2010-03-03 Van 131 WS ORTADOĞU ENERJİ (Oda yeri) 4.245 33.2 2010-02-24 Istanbul 132 HE HETAŞ HACISALİHOĞLU (YILDIZLI HES) 1.200 3.0 2010-02-23 Trabzon 133 HE PETA EN. (MURSAL II HES) 4.500 11.0 2010-02-19 Sivas 134 NG AKBAŞLAR 1.540 11.69 2010-02-18 Bursa 135 WS CEV EN.(GAZİANTEP ÇÖP) 1.131 7.4 2010-02-01 Gaziantep 136 HE ALAKIR (YURT EN.) 2.100 4.0 2010-01-29 Antalya 137 NG ALTINMARKA 4.600 35.9 2010-01-28 Istanbul 138 NG CAN TEKSTİL (Çorlu) 7.832 60.1 2010-01-28 Tekirdag

CDM Executive Board Page 74 139 HE BAYBURT HES 14.600 24.0 2010-01-28 Bayburt 140 HE UZUNÇAYIR 54.660 121.3 2010-01-28 Tunceli 141 LN ETİ SODA 24.000 144.0 2010-01-22 Ankara 142 HE CİNDERE DENİZLİ 9.573 16.7 2010-01-21 Denizli 143 HE KULP IV HES (YILDIZLAR EN.) 12.300 23.0 2010-01-13 Diyarbakir 144 NG TÜPRAŞ (Orta Anadolu-Kırıkkale) 34.000 240.2 2009-12-25 Kirikkale 145 HE SARITEPE HES DİNAMİK SİSTEMLER 2.450 4.5 2009-12-24 Adana 146 NG AKSA ENERJİ (Manisa) 10.500 83.2 2009-12-18 Manisa 147 NG FALEZ ELEKTRİK 11.700 88.0 2009-12-16 Antalya 148 NG ÇELİKLER RİXOS ANKARA OTEL 2.000 16.0 2009-12-15 Ankara 149 NG TAV İSTANBUL 3.260 27.3 2009-12-12 Istanbul 150 HE UZUNÇAYIR 27.330 60.7 2009-12-02 Tunceli 151 HE SARITEPE HES DİNAMİK SİSTEMLER 2.450 4.5 2009-11-19 Adana 152 HE ÖZYAKUT GÜNEŞLİ HES 0.600 1.3 2009-11-13 K.Maras 153 NG SELKASAN 9.900 73.0 2009-11-11 Manisa 154 HE TÜM EN. PINAR 30.100 65.0 2009-11-06 Adiyaman 155 HE ERVA KABACA HES 4.240 7.5 2009-10-29 Artvin 156 NG CAM İŞ ELEKTRİK (Mersin) 126.100 1,008.0 2009-10-19 Mersin 157 NG AKGIDA PAMUKOVA 7.500 61.0 2009-10-17 Sakarya 158 NG MAURİ MAYA 0.330 2.7 2009-10-16 Balikesir 159 FO KIRKA BORAKS (Kırka) 8.200 54.1 2009-10-15 Eskisehir 160 NG DALSAN ALÇI 1.200 9.0 2009-10-14 Kocaeli 161 IC İÇDAŞ ÇELİK 135.000 961.7 2009-10-13 Canakkale 162 HE ERVA KABACA HES 4.240 7.5 2009-09-23 Artvin 163 NG DELTA ENERJİ 13.000 101.2 2009-09-17 Kirklareli 164 FO ALİAĞA PETKİM 52.000 364.0 2009-08-28 Izmir 165 HE DENİZLİ EGE 1 0.900 2.0 2009-08-27 Denizli 166 WS ORTADOĞU ENERJİ (Oda yeri) 5.660 44.3 2009-08-14 Istanbul 167 HE AKÇAY 28.800 45.0 2009-08-14 Aydın 168 NG ENTEK (Köseköy) İztek 12.400 98.7 2009-08-06 Kocaeli 169 NG GLOBAL ENERJİ (PELİTLİK) 8.553 64.0 2009-07-31 Tekirdag 170 NG RASA ENERJİ (VAN) 78.570 499.9 2009-07-31 Van 171 HE OBRUK I-II 210.800 614.0 2009-07-29 Corum 172 IC İÇDAŞ ÇELİK 135.000 961.7 2009-07-24 Canakkale 173 HE KAYEN ALFA EN.KALETEPE HES (tortum) 10.200 17.0 2009-07-23 Erzurum 174 NG ZORLU ENERJİ (B.Karıştıran) 49.530 371.9 2009-07-17 Kirklareli 175 HE AKUA KAYALIK 5.800 20.0 2009-07-15 Erzincan 176 NG AKSA ENERJİ (Antalya) 300.000 2,087.0 2009-07-10 Antalya 177 HE ŞİRİKÇİOĞLU KOZAK 4.400 7.0 2009-07-08 K.Maras 178 HE CİNDERE DENİZLİ 19.146 33.3 2009-07-02 Denizli 179 NG MARMARA PAMUK 34.920 271.5 2009-06-18 Tekirdag 180 NG ANTALYA ENERJİ 41.820 302.2 2009-06-05 Antalya 181 NG AKSA ENERJİ (Antalya) 300.000 2,087.0 2009-05-29 Antalya 182 HE ÖZYAKUT GÜNEŞLİ HES 1.200 2.7 2009-05-29 K.Maras 183 NG MAURİ MAYA 2.000 16.3 2009-05-28 Balikesir 184 BG CARGİLL TARIM 0.100 0.7 2009-05-26 Bursa 185 HE TOCAK I HES (YURT ENERJİ ÜRETİM SAN.) 4.800 6.0 2009-05-08 Antalya 186 AS SİLOPİ ASFALTİT 135.000 945.0 2009-05-02 Sirnak 187 NG NUH ENERJİ (ENER SANT.2) 46.950 352.2 2009-04-30 Kocaeli 188 NG TESKO KİPA İZMİR 2.300 18.0 2009-04-27 Izmir

CDM Executive Board Page 75 189 NG KEN KİPAŞ (KAREN)ELEKTRİK 17.460 75.2 2009-04-23 K.Maras 190 NG DELTA ENERJİ 47.000 365.8 2009-04-21 Kirklareli 191 NG AKSA ENERJİ (Antalya) 16.200 112.7 2009-04-17 Antalya 192 GT GÜRMAT EN. 47.400 313.0 2009-04-02 Aydin 193 NG SÖNMEZ ELEKTRİK 8.730 67.3 2009-03-27 Usak 194 NG KASAR DUAL TEKS.ÇORLU 5.700 38.0 2009-03-26 Tekirdag 195 NG TAV İSTANBUL 6.520 54.7 2009-03-06 Istanbul 196 WS ORTADOĞU ENERJİ (Oda yeri) 4.245 33.2 2009-03-04 Istanbul 197 LN ALKİM (ALKALİ KİMYA) (Konya) 0.400 3.0 2009-02-26 Konya 198 NG ERDEMİR 39.200 236.7 2009-02-06 Zonguldak 199 NG TÜPRAŞ ALİAĞA 24.700 170.0 2009-01-30 Izmir 200 HE TAŞOVA YENİDEREKÖY 2.000 6.0 2009-01-30 Amasya 201 NG AKSA ENERJİ (Manisa) 52.380 414.9 2009-01-15 Manisa 202 NG AKSA ENERJİ (Antalya) 46.700 324.9 2008-12-29 Antalya 203 WS ORTADOĞU ENERJİ (Oda yeri) 2.830 22.1 2008-12-29 Istanbul 204 FO KARKEY (SİLOPİ) 14.780 95.8 2008-12-19 Sirnak 205 HE SARMAŞIK I HES (FETAŞ FETHİYE ENERJİ) 21.000 54.0 2008-11-28 Trabzon 206 HE SARMAŞIK II HES (FETAŞ FETHİYE ENERJİ) 21.600 61.0 2008-11-28 Trabzon 207 HE AKKÖY ENERJİ (AKKÖY HES) 33.980 87.7 2008-11-26 Gumushane 208 NG AKSA ENERJİ (Antalya) 46.700 324.9 2008-11-07 Antalya 209 NG AKSA ENERJİ (Antalya) 46.700 324.9 2008-10-17 Antalya 210 HE TORUL 103.200 264.0 2008-10-16 Gumushane 211 NG AKSA ENERJİ (Manisa) 17.460 138.3 2008-10-10 Manisa 212 HE YEŞİL ENERJİ (TAYFUN HES) 0.800 4.0 2008-10-10 K.Maras 213 HE DAREN HES (SEYRANTEPE BARAJI) 24.850 80.5 2008-09-25 Elazig 214 HE AKKÖY ENERJİ (AKKÖY HES) 67.960 175.3 2008-09-18 Gumushane 215 HE DAREN HES (SEYRANTEPE BARAJI) 24.850 80.5 2008-09-17 Elazig 216 NG AKSA ENERJİ (Manisa) 34.920 276.6 2008-09-16 Manisa 217 NG AKSA ENERJİ (Antalya) 43.700 304.0 2008-09-04 Antalya 218 HE H.G.M.ENER.(KEKLİCEK HES) 8.700 11.0 2008-08-29 Malatya 219 NG ANTALYA ENERJİ 17.460 126.2 2008-08-08 Antalya 220 NG POLAT RÖNESANS 1.600 11.0 2008-08-01 Istanbul 221 HE HİDRO KONTROL YUKARI MANAHOZ 22.400 45.0 2008-07-31 Trabzon 222 NG SÖNMEZ ELEKTRİK 8.730 67.3 2008-07-25 Usak 223 HE CANSU ELEKTRİK (ARTVİN) 9.200 31.0 2008-07-19 Artvin 224 NG MODERN ENERJİ 9.520 66.9 2008-07-04 Tekirdag 225 NG BAHÇIVAN GIDA (LÜLEBURGAZ) 1.200 8.0 2008-07-03 Kirklareli 226 NG MELİKE TEKSTİL G.ANTEP 1.600 11.0 2008-07-03 Gaziantep 227 HE İÇ-EN ELEK. ÇALKIŞLA 7.700 11.0 2008-05-22 Erzincan 228 NG FOUR SEASONS OTEL 1.200 7.0 2008-05-17 Istanbul 229 NG CAN ENERJİ 34.920 202.9 2008-04-02 Tekirdag 230 NG CAN ENERJİ 17.460 101.4 2008-03-07 Tekirdag 231 NG FRİTOLEY GIDA 0.060 0.4 2008-02-23 Kocaeli 232 NG YILDIZ SUNTA (Köseköy) 22.600 146.3 2008-02-22 Kocaeli 233 NG MİSİS APRE TEKSTİL ADANA 2.000 14.0 2008-02-21 Adana 234 NG ATAÇ İNŞSAN. ANTALYA 5.400 37.0 2008-01-30 Antalya 235 HE TEMSA ELEKTRİK (GÖZEDE HES) 2.400 6.0 2008-01-29 Bursa 236 HE ALP ELEKTRİK (TINAZTEPE) 7.700 17.0 2008-01-24 Antalya 237 NG KESKİN KILIÇ SULTANHANI 8.800 60.0 2008-01-04 Aksaray

CDM Executive Board Page 76 238 GT SARAYKÖY JEOTERMAL 6.900 50.0 2008-01-04 Denizli 239 HE MERCAN ZORLU 1.275 3.0 2008-01-01 Tunceli 240 FO KARKEY (SİLOPİ) 29.560 191.6 2007-12-13 Sirnak 241 NG SÜPERBOY BOYA 1.000 8.0 2007-12-06 Istanbul 242 NG FLOKSER TEKSTİL (Poliser) 2.100 17.0 2007-12-04 Istanbul 243 HE KURTEKS (Karasu Andırın HES) 2.400 19.0 2007-11-29 K.Maras 244 NG ACIBADEM Kadıköy 2 0.600 5.0 2007-10-24 Istanbul 245 NG TAV Esenboğa 3.900 33.0 2007-09-20 Ankara 246 NG ALİAĞA Çakmaktepe Enerji 34.840 262.3 2007-09-14 Izmir 247 NG BİS ENERJİ (Bursa San.) 28.300 233.5 2007-09-11 Bursa 248 NG BİS ENERJİ (Bursa San.) 48.000 396.1 2007-08-31 Bursa 249 NG ACIBADEM Bursa 1.300 11.0 2007-08-29 Bursa 250 NG SWISS OTEL (İstanbul) 1.600 11.0 2007-08-02 Istanbul 251 NG AKATEKS Çorlu 1.800 14.0 2007-07-31 Tekirdag 252 NG SAYENERJİ (Kayseri OSB) 5.900 47.0 2007-07-12 Kayseri 253 NG ACIBADEM Kadıköy 1 0.500 4.0 2007-06-20 Istanbul 254 NG ENTEK (Demirtaş) 10.750 81.1 2007-06-15 Bursa 255 NG BİS ENERJİ (Bursa San.) 43.000 354.8 2007-05-31 Bursa 256 HE ÖZGÜR ELEKTR.K.Maraş Tahta HES 6.250 27.0 2007-05-25 K.Maras 257 HE ÖZGÜR ELEKTR.K.Maraş Tahta HES 6.250 27.0 2007-05-04 K.Maras 258 NG HABAŞ (Aliağa) 23.000 184.0 2007-05-03 Izmir 259 NG T. ENERJİ TURCAS 1.600 13.0 2007-04-05 Istanbul 260 FO ORS (Polatlı) 7.400 51.5 2007-03-23 Ankara 261 NG KIVANÇ TEKSTİL 3.900 33.0 2007-03-21 Adana 262 HE BORÇKA 300.600 927.2 2007-02-28 Artvin 263 NG KİL-SAN 3.200 25.0 2007-02-20 Istanbul 264 NG FRİTOLEY GIDA 0.540 3.6 2007-01-24 Kocaeli 265 NG BOSEN (Bursa San.) 11.800 88.6 2007-01-19 Bursa 266 NG AKMAYA (Lüleburgaz) 6.900 48.0 2006-12-23 Kirklareli 267 NG BURGAZ ELEKTRİK 6.900 55.0 2006-12-23 Kirklareli 268 WD ERTÜRK ELEKT. (TEPE) 0.900 2.0 2006-12-22 Istanbul 269 HE BEREKET (MENTAŞ) 13.300 46.7 2006-12-13 Adana 270 NG ÇIRAĞAN SARAYI 1.300 11.0 2006-12-01 Istanbul 271 HE ENERJİ-SA-AKSU-ŞAHMALLAR 14.000 7.0 2006-11-16 Antalya 272 LN ELBİSTAN B 1-4 360.000 1,306.5 2006-11-13 K.Maras 273 NG ENTEK (Köseköy) İztek 37.000 294.6 2006-11-03 Kocaeli 274 NG ÇERKEZKÖY ENERJİ 49.200 403.0 2006-10-06 Tekirdag 275 NG YILDIZ ENTEGRE 6.184 46.3 2006-09-21 Kocaeli 276 LN ELBİSTAN B 1-4 360.000 1,306.5 2006-09-17 K.Maras 277 NG CAM İŞ ELEKTRİK (Mersin) 126.100 1,008.0 2006-09-13 Mersin 278 HE ENERJİ SA-SUGÖZÜ-KIZILDÜZ 15.400 8.0 2006-09-08 Antalya 279 HE EKİN ENERJİ (BAŞARAN HES) 0.600 0.0 2006-08-11 Aydin 280 NG EROĞLU GİYİM 1.200 9.0 2006-08-01 Tekirdag 281 WS EKOLOJİK ENERJİ (Kemerburgaz) 1.000 8.0 2006-07-31 Istanbul 282 HE BEREKET (MENTAŞ) 26.600 93.3 2006-07-31 Adana 283 NG HAYAT TEMİZLİK 15.000 94.0 2006-06-30 Kocaeli 284 NG ANTALYA ENERJİ 34.920 252.4 2006-06-29 Antalya 285 HE SU ENERJİ (ÇAYGÖREN HES) 4.600 4.0 2006-06-27 Balikesir 286 LN ELBİSTAN B 1-4 360.000 1,306.5 2006-06-23 K.Maras 287 NG ŞIK MAKAS 1.600 13.0 2006-06-22 Tekirdag

CDM Executive Board Page 77 288 NG AMYLUM NİŞASTA (Adana) 8.100 45.31 2006-06-09 Adana 289 BG ADANA ATIK 0.800 6.0 2006-06-09 Adana 290 HE MOLU ENERJİ (BAHÇELİK HES) 4.200 30.0 2006-05-31 Kayseri 291 NG KASTAMONU ENTEGRE 7.500 48.0 2006-05-24 Balikesir 292 HE BEREKET (GÖKYAR) 11.600 23.0 2006-05-05 Mugla 293 NG SÖNMEZ ELEKTRİK 17.460 134.6 2006-05-03 Usak 294 NG ELSE TEKSTİL 3.200 25.0 2006-04-15 Tekirdag 295 NG ENTEK (Köseköy) İztek 47.620 379.2 2006-04-14 Kocaeli 296 NG MARMARA PAMUK 8.730 67.9 2006-04-13 Tekirdag 297 NG NUH ENERJİ (ENER SANT.2) 26.080 195.6 2006-03-02 Kocaeli 298 HE ŞANLI URFA 51.000 145.0 2006-03-01 Sanliurfa 299 NG AYDIN ÖRME 7.500 60.0 2006-02-25 Sakarya 300 NG ALARKO ALTEK 21.890 151.4 2006-02-23 Kirklareli 301 NG ERAK GİYİM 1.400 12.0 2006-02-22 Tekirdag 302 NG EKOTEN TEKSTİL 1.900 15.0 2006-02-16 Izmir 303 NG BOSEN (Bursa San.) 51.020 382.9 2005-12-30 Bursa 304 FO KARKEY (SİLOPİ) 6.750 43.8 2005-12-23 Sirnak 305 NT MENDERES TEKS. (AKÇA ENERJİ) 8.730 63.9 2005-12-14 Denizli 306 IC KAHRAMANMARAŞ KAĞIT 6.000 45.0 2005-12-08 K.Maras 307 NG PAKGIDA (Kemalpaşa) 5.700 43.0 2005-12-07 Izmir 308 NG KORUMA KLOR 9.600 77.0 2005-12-03 Kocaeli 309 IC İÇDAŞ ÇELİK 135.000 961.7 2005-11-30 Canakkale 310 NG KÜÇÜKÇALIK TEKSTİL 8.000 64.0 2005-11-27 Bursa 311 NG ZORLU ENERJİ (Yalova) 15.900 122.3 2005-11-26 Yalova 312 NG HABAŞ (Aliağa) 23.000 184.0 2005-11-24 Izmir 313 NG GRANİSER GRANİT 5.500 42.0 2005-11-14 Manisa 314 NG MANİSA O.S.B. 84.834 678.2 2005-11-11 Manisa 315 NG AK ENERJİ (Kemalpaşa) 40.000 328.3 2005-11-09 Izmir 316 NG ZORLU ENERJİ (Kayseri) 38.630 294.9 2005-10-26 Kayseri 317 NG ALARKO ALTEK 60.100 415.6 2005-10-14 Kirklareli 318 NG AYKA TEKSTİL 5.500 41.0 2005-09-24 Tekirdag 319 NG HABAŞ (Aliağa) 44.615 357.0 2005-09-21 Izmir 320 NG EVYAP 5.100 30.0 2005-08-27 Istanbul 321 NG ÇEBİ ENERJİ 21.000 164.8 2005-08-27 Tekirdag 322 NG CAN ENERJİ 3.900 22.7 2005-08-25 Tekirdag 323 NG NOREN ENERJİ 8.700 70.0 2005-08-24 Nigde 324 NG ÇEBİ ENERJİ 43.366 340.2 2005-08-23 Tekirdag 325 HE YAMULA 100.000 422.0 2005-07-30 Kayseri 326 NG ZORLU ENERJİ (Kayseri) 149.871 1,144.1 2005-07-22 Kayseri 327 BG BANDIRMA ASİT(ETİ MADEN) 11.500 88.0 2005-07-15 Balikesir 328 HE BEREKET (DALAMAN) 7.500 35.8 2005-07-15 Mugla 329 NG ZEYNEP GİYİM 1.200 9.0 2005-07-07 Tekirdag 330 FO KARKEY (SİLOPİ) 6.150 39.9 2005-06-30 Sirnak 331 NG AKBAŞLAR 5.040 38.25 2005-06-24 Bursa 332 NG MODERN ENERJİ 10.240 72.0 2005-06-13 Tekirdag 333 HE MURATLI 115.000 460.5 2005-06-02 Artvin 334 NG HABAŞ (Aliağa) 44.615 357.0 2005-06-02 Izmir 335 NG TEZCAN GALVANİZ GR I-II 3.500 28.0 2005-05-27 Kocaeli 336 NG HAYAT KAĞIT SAN. 7.200 56.3 2005-05-27 Corum 337 NG YONGAPAN (Kastamonu) 5.200 30.5 2005-05-25 Kocaeli

CDM Executive Board Page 78 338 NG NUH ENERJİ (ENER SANT.2) 46.950 352.2 2005-05-24 Kocaeli 339 HE İÇTAŞ YUKARI MERCAN 14.200 20.0 2005-05-21 Erzincan 340 NG AK ENERJİ (Kemalpaşa) 87.200 715.7 2005-04-30 Izmir 341 WD SUNJÜT 1.200 2.0 2005-04-22 Istanbul 342 NG KAREGE ARGES 17.460 138.9 2005-04-07 Izmir 343 NG BİS ENERJİ (Bursa San.) 43.700 360.6 2005-03-18 Bursa 344 LN ÇAN 1-2 160.000 976.5 2005-03-15 Canakkale 345 LN ÇAN 1-2 160.000 976.5 2005-02-15 Canakkale 346 LN ELBİSTAN B 1-4 360.000 1,306.5 2005-02-15 K.Maras 347 NG ENTEK (KOÇ Üniversite) 2.300 19.0 2005-02-07 Istanbul 348 NG BAYDEMİRLER (Beylikdüzü) 6.210 51.5 2005-02-04 Istanbul 349 NG MERCEDES BENZ 8.300 68.0 2005-02-04 Istanbul 350 NG GLOBAL ENERJİ (PELİTLİK) 11.748 87.8 2005-01-29 Tekirdag 351 NG GLOBAL ENERJİ (HACIŞİRAHMET) 7.800 58.0 2005-01-29 Tekirdag 352 FO TÜPRAŞ (Batman) 1.500 10.5 2004-12-31 Batman 353 NG BAHARİYE MENSUCAT 1.000 7.0 2004-12-31 Istanbul 354 NG ALTINMARKA 3.596 28.1 2004-12-17 Istanbul 355 FO KARKEY (SİLOPİ) 54.300 351.9 2004-11-12 Sirnak 356 NG STANDARD PROFİL 6.700 49.0 2004-10-22 Duzce 357 NG HABAŞ (Aliağa) 89.230 714.0 2004-10-08 Izmir 358 NG AYEN OSTİM 9.890 84.0 2004-10-01 Ankara 359 NG KOMBASSAN AMBALAJ (Konya) 5.500 40.0 2004-09-24 Konya 360 HE BEREKET (FESLEK) 9.500 25.0 2004-08-05 Aydin 361 NG ÇELİK ENERJİ (Uzunçiftlik) 2.400 19.0 2004-07-09 Kocaeli 362 NG BERK ENERJİ (BESLER -KURTKÖY) 4.400 30.9 2004-07-07 Istanbul 363 NG ŞAHİNLER ENERJİ(ÇORLU/TEKİRDAĞ) 3.200 22.8 2004-06-29 Tekirdag 364 NG ENERJİ-SA (Adana) 49.770 325.0 2004-06-23 Adana 365 NG BİS ENERJİ (Bursa San.) 73.000 602.3 2004-06-16 Bursa 366 NG AYEN OSTİM 31.077 264.0 2004-06-11 Ankara 367 NG KOMBASSAN AMBALAJ (Tekirdağ) 5.500 38.0 2004-06-09 Tekirdag 368 NG TEKBOY TEKSTİL 2.200 16.0 2004-05-18 Kirklareli 369 IC ÇOLAKOĞLU-2 45.000 337.5 2004-05-05 Kocaeli 370 HE İŞKUR (SÜLEYMANLI HES) 4.600 4.0 2004-04-28 K.Maras 371 HE ELTA (DODURGA) 4.100 12.0 2004-04-26 Denizli 372 LPG ETİ BOR (EMET) 10.400 82.0 2004-04-22 Kutahya 373 NG TANRIVERDİ 4.700 39.0 2004-03-24 Tekirdag 374 HE ENERJİ-SA BİRKAPILI 48.500 17.0 2004-03-11 Mersin 375 NG ATATEKS TEKSTİL 5.600 45.0 2004-02-20 Tekirdag 376 NG ENTEK (Demirtaş) 31.132 234.7 2004-02-12 Bursa 377 NG ANKARA 798.000 5,209.0 2004-01-08 Ankara 378 NG ECZACIBAŞI BAXTER 1.000 6.0 2003-12-31 Istanbul 379 NG SÖNMEZ FLAMENT 4.100 29.0 2003-12-31 Bursa 380 IC İSKENDERUN 1,320.000 7,706.0 2003-11-22 Hatay 381 NG ENERJİ-SA (Mersin) 21.575 177.4 2003-11-22 Mersin 382 HE BATMAN 198.500 450.0 2003-11-14 Batman 383 NG ENERJİ-SA (Çanakkale) 21.575 175.0 2003-11-12 Canakkale 384 NG BATIÇİM ENERJİ (AK ENERJİ) 14.500 119.3 2003-10-26 Izmir 385 HE PAMUK (Toroslar) 23.300 28.0 2003-10-18 Mersin 386 HE MERCAN ZORLU 19.100 45.0 2003-10-08 Tunceli 387 NG ENERJİ-SA (Mersin) 41.650 342.6 2003-10-05 Mersin

CDM Executive Board Page 79 388 HE KÜRTÜN 85.000 132.9 2003-09-26 Gumushane 389 FO ANADOLU EFES BİRA I 3.800 32.0 2003-09-05 Ankara 390 NG ZORLU ENERJİ (Sincan) 10.660 90.8 2003-07-18 Ankara 391 NG BAYDEMİRLER (Beylikdüzü) 2.066 17.1 2003-07-11 Istanbul 392 NG TÜBAŞ 1.400 9.0 2003-07-11 Tekirdag 393 NG PAKGIDA (Düzce-Köseköy) 2.100 16.7 2003-07-02 Duzce 394 NG ÖZAKIM ENERJİ (Gürsu) 7.000 60.0 2003-06-19 Bursa 395 NG KEN KİPAŞ (KAREN)ELEKTRİK 24.340 104.8 2003-06-14 K.Maras 396 HE YAPISAN HACILAR DARENDE 13.300 54.0 2003-06-14 Malatya 397 NG ZORLU ENERJİ (Sincan) 39.700 338.2 2003-05-31 Ankara 398 NG CAN TEKSTİL (Çorlu) 0.900 6.9 2003-05-17 Tekirdag 399 NG YURTBAY (Eskişehir) 6.900 50.0 2003-05-16 Eskisehir 400 NT ALKİM KAĞIT 3.385 26.7 2003-05-03 Afyon 401 NG İZMİR 1,590.700 10,780.0 2003-03-28 Izmir 402 NG BATIÇİM ENERJİ (AK ENERJİ) 25.400 208.9 2003-03-13 Izmir 403 NG HAYAT KİMYA (İzmit) 5.200 32.0 2003-03-11 Kocaeli 404 FO ALİAĞA PETKİM 21.700 151.9 2003-02-24 Izmir 405 HE EŞEN-II (GÖLTAŞ) 21.700 40.0 2003-01-31 Mugla 406 NG BATIÇİM ENERJİ (AK ENERJİ) 5.080 41.8 2003-01-27 Izmir 407 LN ETİ MADEN (BANDIRMA BORAKS) 10.700 78.0 2003-01-10 Balikesir 408 NG BURSA D.GAZ 1,432.000 9,711.0 1998-01-01 Bursa 409 DO VAN ENGİL GAZ (ZORLU ENERJİ) 15.000 75.0 1996-01-01 Van 410 LN KEMERKÖY 630.000 2,698.0 1993-01-01 Mugla 411 LN ORHANELİ 210.000 950.0 1992-01-01 Bursa 412 HC ÇATALAĞZI-B 300.000 1,721.1 1989-01-01 Zonguldak 413 LN KANGAL 457.000 2,391.0 1989-01-01 Sivas 414 NG AMBARLI-D.GAZ 1,350.900 7,919.0 1988-01-01 Istanbul 415 LN ÇAYIRHAN PARK HOLD. 620.000 3,601.0 1987-01-01 Ankara 416 LN YENİKÖY 420.000 2,150.0 1986-01-01 Mugla 417 NG HAMİTABAT 1,156.000 6,804.0 1985-01-01 Kirklareli 418 LN ELBİSTAN A 1,355.000 3,144.0 1984-01-01 K.Maras 419 GT ZORLU ENERJİ (DENİZLİ) 15.000 105.0 1984-01-01 Denizli 420 LN YATAĞAN 630.000 2,869.0 1982-01-01 Mugla 421 LN SOMA B 990.000 4,715.0 1981-01-01 Manisa 422 NG ALİAĞA-ÇEVRİM 180.000 1,025.0 1975-01-01 Izmir 423 FO HOPA 50.000 241.6 1973-01-01 Artvin 424 LN SEYİTÖMER 600.000 3,201.0 1973-01-01 Kütahya 425 FO AMBARLI 630.000 0.0 1967-01-01 Istanbul 426 LN SOMA A 44.000 0.0 1957-01-01 Manisa 427 HE BİLGİN ELEK. (HAZAR 1-2) 30.100 0.0 1957-01-01 Elazig 428 LN TUNÇBİLEK 365.000 1,499.0 1956-01-01 Kütahya 429 DO HAKKARİ ÇUKURCA 1.000 0.0 Hakkari 430 HE ADIGÜZEL 62.000 146.4 Denizli 431 HE ALMUS 27.000 93.4 Tokat 432 HE ALTINKAYA 702.600 1,616.0 Samsun 433 HE ASLANTAŞ 138.000 674.9 Osmaniye 434 HE ATATÜRK 2,405.000 8,139.9 Sanliurfa 435 HE BERDAN 10.200 15.0 Mersin 436 HE ÇATALAN 168.900 646.0 Adana 437 HE ÇAMLIGÖZE 32.000 97.5 Sivas

CDM Executive Board Page 80 438 HE DEMİRKÖPRÜ 69.000 102.7 Manisa 439 HE DERBENT 56.400 289.0 Samsun 440 HE DİCLE 110.000 180.8 Diyarbakir 441 HE DOĞANKENT 74.500 220.0 Giresun 442 HE GEZENDE 159.400 220.0 Mersin 443 HE GÖKÇEKAYA 278.400 471.1 Eskisehir 444 HE HASAN UĞURLU 500.000 1,182.0 Samsun 445 HE HASANLAR 9.400 29.6 Bolu 446 HE HİRFANLI 128.000 290.0 Kirsehir 447 HE KAPULUKAYA 54.000 194.1 Kirikkale 448 HE KARACAÖREN-1 32.000 72.7 Burdur 449 HE KARACAÖREN II 46.400 123.0 Burdur 450 HE KARAKAYA 1,800.000 8,383.8 Diyarbakir 451 HE KARKAMIŞ 189.000 672.9 Gaziantep 452 HE KEBAN 1,330.000 7,110.0 Elazig 453 HE KEMER 48.000 78.2 Aydin 454 HE KESİKKÖPRÜ 76.000 173.2 Ankara 455 HE KILIÇKAYA 120.000 300.0 Sivas 456 HE KÖKLÜCE 90.000 450.0 Tokat 457 HE KRALKIZI 94.500 50.0 Diyarbakir 458 HE KISIK 9.300 24.0 K.Maras 459 HE MANAVGAT 48.000 143.0 Antalya 460 HE MENZELET 124.000 603.0 K.Maras 461 HE ÖZLÜCE 170.000 593.9 Elazig 462 HE SARIYAR 160.000 310.1 Ankara 463 HE SUAT UĞURLU 69.000 358.0 Samsun 464 HE TORTUM 26.200 113.0 Erzurum 465 HE YENİCE 37.900 118.7 Ankara 466 HE BERKE 510.000 1,614.0 Osmaniye 467 HE SEYHAN I 60.000 447.1 Adana 468 HE SEYHAN II 7.500 6.0 Adana 469 HE SIR 283.500 732.1 K.Maras 470 HE KADINCIK I 70.000 200.0 Mersin 471 HE KADINCIK II 56.000 175.0 Mersin 472 HE YÜREĞİR 6.000 4.5 Adana 473 HE KEPEZ I-II 32.400 90.0 Antalya 474 HE OTHERS 45.000 100.0 475 HE ADİLCEVAZ(MOSTAR EN.) 0.400 0.5 Bitlis 476 HE AHLAT(MOSTAR EN.) 0.200 0.5 Bitlis 477 HE BAYBURT(BOYDAK EN.) 0.400 1.7 Bayburt 478 HE BESNİ(KAYSERİ VE CİVARI EN.ÜR.) 0.300 0.2 Adiyaman 479 HE BÜNYAN(KAYSERİ VE CİVARI) 1.200 3.2 Kayseri 480 HE ÇAĞ-ÇAĞ(NAS EN.) 14.400 22.0 Mardin 481 HE ÇAMARDI(KAYSERİ VE CİVARI EN.ÜR.) 0.100 0.1 Nigde 482 HE ÇEMİŞKEZEK(BOYDAK EN.) 0.100 0.5 Tunceli 483 HE DEĞİRMENDERE(KA-FNIH EL.) 0.500 0.8 Osmaniye 484 HE DERME(KAYSERİ VE CİVARI EN.ÜR.) 4.500 7.0 Malatya 485 HE ERKENEK(KAYSERİ VE CİVARI EN.ÜR.) 0.300 0.5 Malatya 486 HE GİRLEVİK(BOYDAK EN.) 3.000 19.0 Erzincan 487 HE HAKKARİ (OTLUCA)((NAS EN.) 1.300 5.0 Hakkari

CDM Executive Board Page 81 488 HE İNEGÖL(CERRAH)(KENT SOLAR EL.) 0.300 0.8 Bursa 489 HE İZNİK (DEREKÖY)(KENT SOLAR EL.) 0.200 0.9 Bursa 490 HE KARAÇAY(OSMANİYE)(KA-FNIH EL.) 0.400 2.0 Osmaniye 491 HE KAYADİBİ(BARTIN)(İVME ELEKTROMEKANİK 0.500 2.0 Bartin 492 HE KERNEK(KAYSERİ VE CİVARI EN.ÜR.) 0.800 0.6 Malatya 493 HE KOVADA-I(BATIÇİM EN.) 8.300 1.6 Isparta 494 HE KOVADA-II(BATIÇİM EN.) 51.200 24.4 Isparta 495 HE KUZUCULU (DÖRTYOL)(KA-FNIH EL.) 0.300 1.0 Hatay 496 HE M.KEMALPAŞA(SUUÇTU)(KENT SOLAR EL.) 0.500 1.3 Bursa 497 HE MALAZGİRT(MOSTAR EN.) 1.200 3.0 Mus 498 HE PINARBAŞI(KAYSERİ VE CİVARI EN.ÜR.) 0.100 0.3 Kayseri 499 HE SIZIR(KAYSERİ VE CİVARI EN.ÜR.) 5.800 35.0 Kayseri 500 HE TURUNÇOVA(FİNİKE)(TURUNÇOVA EL.) 0.600 0.8 Antalya 501 HE ULUDERE(NAS EN.) 0.600 2.6 Sirnak 502 HE VARTO(MOSTAR EN.) 0.300 0.6 Mus 503 NG GEBZE D.GAZ 1,595.400 10,951.0 Sakarya 504 NG ADAPAZARI 797.700 5,473.0 Sakarya 505 NG TRAKYA ELEKTRİK ENRON 498.700 3,797.0 Tekirdag 506 NG ESENYURT (DOĞA) 188.500 1,400.0 Istanbul 507 NG OVA ELEK. 258.400 2,019.0 Kocaeli 508 NG UNİMAR 504.000 3,797.0 Tekirdag 509 HE BİRECİK 672.000 2,092.0 Sanliurfa 510 HE AHİKÖY I-II 4.200 21.0 Sivas 511 HE AKSU (ÇAYKÖY) 16.000 35.0 Burdur 512 HE ÇAL (LİMAK) (Denizli) 2.500 12.0 Denizli 513 HE ÇAMLICA (AYEN ENERJİ) 84.000 429.0 Kayseri 514 HE DİNAR-II (METAK) 3.000 16.0 Afyon 515 HE FETHİYE 16.500 89.0 Mugla 516 HE GAZİLER (Iğdır) 11.200 48.0 Igdir 517 HE GİRLEVİK-II / MERCAN 11.000 39.0 Erzincan 518 HE GÖNEN 10.600 47.0 Balıkesir 519 HE SUÇATI (ERE EN.) 7.000 28.0 K.Maras 520 HE SÜTCÜLER 2.300 13.0 Isparta 521 HE TOHMA MEDİK (ALARKO) 12.500 59.0 Malatya 522 WD ARES (ALAÇATI) 7.200 19.0 Izmir 523 WD BORES (BOZCAADA) 10.200 31.0 Canakkale 524 FO AKSU SEKA (MİLDA KAĞIT) 8.000 20.0 Giresun 525 FO ALİAĞA PETKİM 148.300 1,038.1 Izmir 526 FO ALBAYRAK TURİZM(BALIKESİR SEKA) 9.300 56.0 Balikesir 527 FO BOR ŞEKER 9.600 6.0 Nigde 528 FO OYKA KAĞ.(CAYCUMA SEKA) 10.000 70.0 Zonguldak 529 FO ERDEMİR 73.500 450.0 Zonguldak 530 FO HALKALI KAĞIT 5.100 39.0 Istanbul 531 FO MED UNİON A.Ş. (EBSO) 3.400 26.9 Izmir 532 FO MOPAK (Dalaman) 26.200 106.0 Mugla 533 FO S.ŞEHİR (ETİ) ALÜMİNYUM 11.900 35.0 Konya 534 FO TÜPRAŞ İZMİR (ALİAĞA RAF.) 44.000 306.0 Izmir 535 FO TÜPRAŞ (İzmit-Yarımca) 45.000 291.2 Kocaeli 536 FO TÜPRAŞ (Batman) 8.800 Batman

CDM Executive Board Page 82 537 FO TİRE-KUTSAN (Tire) 8.000 37.0 Izmir 538 FO OTHERS (Isolated) 96.000 300.0 539 DO TÜPRAŞ (Batman) 10.300 72.0 Batman 540 DO OTHERS 0.100 1.0 541 IC ÇOLAKOĞLU-2 145.000 1,087.5 Kocaeli 542 HC İSDEMİR 220.400 772.0 Hatay 543 HC KARDEMİR 35.000 300.0 Zonguldak 544 LN ALKİM (ALKALİ KİMYA) (Dazkırı) 2.500 17.0 Afyon 545 LN PETLAS 6.000 40.0 Kirsehir 546 LN MARMARA KAĞIT (Bilorsa) 2.000 9.0 Bilecik 547 LN OTHERS 147.500 285.0 548 LPG GOODYEAR (Adapazarı) 9.600 79.0 Sakarya 549 LPG GOODYEAR (İzmit) 4.200 35.0 Kocaeli 550 LPG MOPAK KAĞIT (Işıklar) 4.600 33.0 Izmir 551 LPG ORTA ANADOLU MENSUCAT 10.000 65.0 Kayseri 552 NT MENDERES TEKS. (AKÇA ENERJİ) 10.400 76.1 Denizli 553 NT ALKİM KAĞIT 1.815 14.3 Afyon 554 NT DENTAŞ (Denizli) 5.000 38.0 Denizli 555 NT MENSA MENSUCAT 10.400 85.0 Adana 556 NT TOROS (Ceyhan) 4.700 38.0 Adana 557 NT TOROS (Mersin) 12.100 96.0 Mersin 558 NG AKIN ENERJİ (B.Karıştıran) 4.900 37.0 Kirklareli 559 NG ALTINYILDIZ (Yenibosna) 4.700 40.0 Istanbul 560 NG ARÇELİK (Eskişehir) 6.300 49.0 Eskisehir 561 NG ARÇELİK (Çayırova) 6.500 48.0 Kocaeli 562 NG ATLAS HALICILIK (Çorlu) 1.000 7.0 Tekirdag 563 NG BAYDEMİRLER (Beylikdüzü) 1.000 8.3 Istanbul 564 NG CAN TEKSTİL (Çorlu) 4.300 33.0 Tekirdag 565 NG COGNİS (Tuzla)* 1.000 8.0 Izmir 566 NG ÇOLAKOĞLU-1 123.400 1,047.0 Kocaeli 567 NG DOĞUŞ (B.Karıştıran) 1.000 8.0 Tekirdag 568 NG GÜLLE ENTEGRE (Çorlu) 6.300 29.0 Tekirdag 569 NG İGSAŞ (Yarımca) 11.000 76.0 Kocaeli 570 NG SANKO (İSKO) (İnegöl) 9.200 63.0 Bursa 571 NG KALESERAMİK (Çan Seramik+Kalebodur) 21.600 157.0 Canakkale 572 NG KARTONSAN (İzmit) 24.000 192.0 Kocaeli 573 NG NUR YILDIZ (GEM-TA)* 1.400 7.0 Tekirdag 574 NG SARKUYSAN (Tuzla) 7.700 60.0 Kocaeli 575 NG SAMUR HALI A.Ş. 4.300 33.0 Ankara 576 NG TERMAL SERAMİK (Söğüt) 4.600 34.0 Bilecik 577 NG TRAKYA İPLİK (Çerkezköy) 4.200 29.0 Tekirdag 578 NG YILFERT (TÜGSAŞ GEMLİK GÜB.) 8.000 50.0 Bursa 579 NG TÜP MERSERİZE (B.Karıştıran) 1.000 7.0 Tekirdag 580 NG YILDIZ SUNTA (Köseköy) 5.200 33.7 Kocaeli 581 NG YONGAPAN (Kastamonu) 5.200 30.5 Kocaeli 582 NG OTHERS 84.100 296.0 583 BG BELKA (Ankara) 3.200 22.0 Ankara 584 BG KEMERBURGAZ 4.000 7.0 Istanbul 585 BG BANDIRMA BAĞFAŞ 10.000 57.0 Balikesir 586 HE OYMAPINAR (ETİ ALİMİNYUM) 540.000 1,170.0 Antalya

CDM Executive Board Page 83 587 HE BAĞCI SU ÜRÜNLERİ 0.300 1.7 Mugla 588 HE MOLU 3.400 10.6 Kayseri 589 HE YEŞİLLİLER (Kırşehir) 0.500 1.0 Kirsehir 590 NT ATAER ENERJİ (EBSO) 70.200 398.1 Izmir 591 NG AK ENERJİ (Bozüyük) 126.600 817.0 Bilecik 592 NG AK ENERJİ (Çerkezköy) 98.000 805.0 Tekirdag 593 NG ARENKO DENİZLİ 12.000 84.0 Denizli 594 NG AKIM EN. BAŞPINAR(SÜPER FİLM)G.ANTEP 25.300 177.0 Gaziantep 595 NG AKSA AKRİLİK KİMYA (YALOVA) 59.500 450.0 Yalova 596 NG BERK ENERJİ (BESLER -KURTKÖY) 10.400 73.1 Istanbul 597 NG BİS ENERJİ (Bursa San.) 174.000 1,435.7 Bursa 598 NG BOSEN (Bursa San.) 80.000 600.5 Bursa 599 NG BİL ENERJİ (Ankara) 36.600 255.0 Ankara 600 NG EGE BİRLEŞİK ENERJİ 12.800 107.0 Izmir 601 NG CAM İŞ ELEKTRİK (B.Karıştıran) 32.900 270.0 Kirklareli 602 NG CENGİZ ENERJİ ÇİFT YAK. 131.300 985.0 Samsun 603 NG DESA ENERJİ 9.800 70.0 Izmir 604 NG ENERJİ-SA (Adana) 80.400 525.0 Adana 605 NG ENERJİ-SA (Çanakkale) 42.525 345.0 Canakkale 606 NG ENERJİ-SA (Kentsa) Köseköy 120.000 930.0 Kocaeli 607 NG ENTEK (Köseköy) İztek 60.100 478.5 Kocaeli 608 NG ENTEK (Demirtaş) 104.000 784.2 Bursa 609 NG MAKSİ ENERJİ 7.700 55.0 Istanbul 610 NG MODERN ENERJİ 77.000 541.1 Tekirdag 611 NG NUH ENERJİ 1 (Nuh Çimento) 38.000 326.0 Kocaeli 612 NG SAMSUN TEKKEKÖY (AKSA EN.) 131.300 980.0 Samsun 613 NG ŞAHİNLER ENERJİ(ÇORLU/TEKİRDAĞ) 22.800 162.2 Tekirdag 614 NG YENİ UŞAK ENERJİ 8.700 65.0 Usak 615 NG ZORLU ENERJİ (Bursa) 90.000 752.0 Bursa 616 NG ZORLU ENERJİ (B.Karıştıran) 65.800 494.1 Kirklareli 617 NG ESKİŞEHİR ENDÜSTRİ ENERJİ(OSB) 59.000 451.8 Eskisehir 618 WS İZAYDAŞ (İzmit çöp) 5.200 37.0 Kocaeli 619 FO AKSA ENERJİ (Hakkari) 24.000 175.0 Hakkari 620 FO HABAŞ (Bilecik) 18.000 144.0 Bilecik 621 FO HABAŞ (İzmir) 36.000 288.0 Izmir 622 FO KIZILTEPE 33.000 250.0 Mardin 623 FO PS3-1 (SİLOPİ) 44.100 285.8 Sirnak 624 FO PS3-2 (SİLOPİ) 29.500 191.2 Sirnak 625 FO PS3-A -1 11.000 80.0 Sirnak 626 FO PS3-A -2 (İDİL) 24.000 180.0 Sirnak 627 FO SİİRT 24.000 190.0 Siirt 628 HE BEREKET (DENİZLİ) 3.700 12.0 Denizli 629 HE BEREKET (DALAMAN) 30.000 143.2 Mugla 630 HE EŞEN-II (GÖLTAŞ) 21.700 40.0 Mugla 631 HE KAREL (PAMUKOVA) 9.300 55.0 Sakarya 632 HE MURGUL BAKIR 4.700 7.5 Artvin 633 HE BEYKÖY ZORLU 16.800 87.0 Eskisehir 634 HE KUZGUN ZORLU 20.900 0.0 Erzurum 635 HE TERCAN ZORLU 15.000 28.0 Erzincan 636 HE ATAKÖY ZORLU 5.500 8.0 Tokat

CDM Executive Board Page 84 637 HE ÇILDIR ZORLU 15.400 20.0 Kars 638 HE İKİZDERE ZORLU 18.600 100.0 Rize 639 WD ALİZE ENERJİ (DELTA PLASTİK) 1.500 4.0 Izmir TOTAL 49,468.3 256,636.4 51,327.3 20% AEG total AEG SET-=20 per cent 256,636,38 2 MWh 51,327,276 MWh Abbreviations: AS: Asphaltite, BG: Biogas, DO: Diesel Oil, FO: Fuel Oil, GT: Geothermal, HC: Hard Coal, HE: Hydroelectric, IC: Imported Coal, LN: Lignite, LPG: Liquefied Petroleum Gas, NG: Natural Gas, NT: Naphta, WD. Wind, WS: Waste Appendix 5: Further background information on monitoring plan Not available. Appendix 6: Summary of post registration changes Not available. - - - - - History of the document Version Date Nature of revision 04.1 11 April 2012 Editorial revision to change version 02 line in history box from Annex 06 to Annex 06b. 04.0 EB 66 13 March 2012 03 EB 25, Annex 15 26 July 2006 02 EB 14, Annex 06b 14 June 2004 01 EB 05, Paragraph 12 03 August 2002 Decision Class: Regulatory Document Type: Form Business Function: Registration Revision required to ensure consistency with the Guidelines for completing the project design document form for CDM project activities (EB 66, Annex 8). Initial adoption.