PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 … · PROJECT DESIGN DOCUMENT FORM (CDM PDD) -...

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03

CDM – Executive Board page 1

0CLEAN DEVELOPMENT MECHANISM

PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 03 - in effect as of: 28 July 2006

CONTENTS

A. General description of project activity B. Application of a baseline and monitoring methodology C. Duration of the project activity / crediting period D. Environmental impacts E. Stakeholders’ comments

Annexes

Annex 1: Contact information on participants in the project activity Annex 2: Information regarding public funding Annex 3: Baseline information

Annex 4: Monitoring plan



SECTION A. General description of project activity

A.1. Title of the project activity: >> Project Title: Sayalar Wind Farm Capacity Addition Project, Turkey PDD version: 1.0 Date: 13.10.2011

A.2. Description of the project activity: >> Summary:

The Sayalar Wind Farm is located in Agean Region, Manisa – Akhisar Province, Sayalar District in Turkey and is currently operational with an installed capacity of 34.2 MW (Hereafter referred as existing power plant. The existing power plant consists of 38 turbines with a capacity of 900 kW each. The existing 34.2 MW capacity of Sayalar Wind Farm has been registered as a Gold Standard VER project on 01/11/2007 under the registration number GS369 by “Doğal Enerji Elektrik Üretim A.Ş.”1. The Project Participant is planning to increase the existing 34.2 MW capacity to 54.2 MW installed capacity with a 20MW capacity addition (hereafter referred as the proposed project activity) to the existing power plant2. The proposed project activity is developed by “Doğal Enerji Elektrik Üretim A.Ş.” (Hereafter referred as the project participant) and involves the installation of 10 wind turbines. The electricity generation from the capacity addition is estimated to reach approximately 55 GWh/year3 and will be delivered to the national grid via Akhisar Transformer Station. The project activity aims to reduce GHGs by replacing electricity generation from the Turkish national grid system with electricity generation from wind energy, which has zero emissions. In accordance with the applicable methodology ACM0002 “Consolidated baseline methodology for grid connected electricity generation from renewable sources” v.12.1.0, the baseline emissions include only CO2 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. The annual emission reductions, which will result from the capacity addition, are estimated as 34,477 tCO2eq/year. Contribution to Sustainable Development:

Renewable wind energy is an energy source that offers various environmental benefits. It does not result in emissions of pollutants into the atmosphere, nor does it emit residuals that can have an impact on soil

1 Reference: The Gold Standard Foundation Official Webpage, Public Reports, VER Projects / https://gs1.apx.com/myModule/rpt/myrpt.asp?r=111

2 Reference: Generation License available to the DOE.

3 Reference: Technical Feasibility (micrositing) available to the DOE



and water. The net result is a reduction of fossil fuel consumption that would occur in power stations connected to the national grid so as to produce an equivalent amount of energy. At the same time, wind energy is a renewable source. So it does not endanger the supply of energy for future generations. The project contributes significantly to the region’s sustainable development in the following ways:

• Wind energy is a renewable energy source. Unlike fossil fuels, it does not reduce the availability of energy for future generations.

• Reduction of greenhouse gas emissions and other pollutants in Turkey by replacing electricity otherwise generated by the Turkey’s national grid, which has a large share of fossil fuel power generation4.

• The project also reduces other emissions than GHG such as emissions of sulfur dioxide, nitrogen oxides, and particulates. In turn it contributes to local improvement of air quality.

• The project will enable the use of renewable energy in Turkey and attract foreign and private investment into the Turkey’s power sector.

• The project strengthens the involvement of Turkey in renewable energies and low carbon power production through the use of market mechanisms.

• Creation of local employment both during the construction and operational phase. Based on 2010 figures, the unemployment rate is above 11% in Turkey5.

• Technology and know-how transfer. • Power supply improvement to the national grid both for domestic and commercial consumers. • Diversification of electricity generation technologies in Turkey, which is currently dominated by

natural gas fired power plants. Additionally, no major negative impacts are expected as confirmed by the Local Stakeholders Consultation Meeting.

A.3. Project participants:

>> Name of Party involved (*)

(host indicates a Host Party)

Private and/or public

entity(ies) project participants

(*) (as a applicable)

Kindly indicate if the Party

involved wishes to be

considered as project

participant (Yes/No)

Turkey (host) Doğal Enerji Elektrik Üretim A.Ş.

No

Doğal Enerji Elektrik Üretim A.Ş. is a special purpose company established jointly by Demirer Enerji Üretim Sanayi ve Ticaret A.Ş.6 and Polat Enerji Sanayi ve Ticaret A.Ş7.

4 80% of the total electricity generation of Turkey is from thermal power plants. Reference: TEIAS (Turkish Electricity Transmission Co) official webpage, 2009 statistics / http://www.teias.gov.tr/istatistik2009/32(75-09).xls

5 Reference: TUĐK (Turkish Stastical Institute) 2010 Statistical Yearbook Section 11 p193 http://www.teias.gov.tr/istatistik2009/32(75-09).xls

6 Reference: www.demirer.com.tr

7 Reference: http://www.polatenerji.com/polat.php



OakDanışmanlık is the carbon consultant for this project8. Full contact information for the project participants are provided in Annex 1.

A.4. Technical description of the project activity:

A.4.1. Location of the project activity:

A.4.1.1. Host Party(ies): >> Republic of Turkey

A.4.1.2. Region/State/Province etc.: >> Aegean Region, Manisa Province

A.4.1.3. City/Town/Community etc.:

>> The proposed project is located in Manisa – Akhisar Province Sayalar District. The closest residential area is the Deremahallesi Village.

8 OakDanışmanlık is not a project participant



A.4.1.4. Details of physical location, including information allowing the

unique identification of this project activity (maximum one page):

>> Figure 1: The geographic location of the proposed project activity

The coordinates of the centre point of the proposed project activity is 39°11'52.45" N; 27°57'45.55"E. The coordinates of the turbines are available to the DOE.



A.4.2. Category(ies) of project activity: >> Table 1. Categories of the project activity Applicable rules and

definitions

Category Justification

UNFCCC Sectoral scope 1, Energy Industries (renewable/non-renewable sources)9.

The proposed project activity involves grid connected electricity generation from renewable sources.

Gold Standard Large scale Renewable Energy Supply10.

The project exceeds the small scale project threshold of 15 MW installed capacity and involves generation and delivery of energy services from non-fossil and non-deplatable energy sources.

A.4.3. Technology to be employed by the project activity:

>> The proposed project activity involves the installation of 10 units of additional wind turbines with a total installed capacity of 20 MW. The project activity is expected to generate approximately 55 GWh/year of net electricity. The total capacity addition will be reached by installation of Enercon gearless turbines. The key technical specifications of the turbines are as follows: Table2. Key technical specifications of wind turbines Parameter Value

Rated Power 2MW Rotor Diameter 71 - 82 m Turbine Concept Gearless, variable speed, single blade adjustment Rotor Type Upwind rotor with active pitch control Number of blades 3 Swept Area 3959 - 5281 m2 Hub Height 78 – 85 m Blade Material GRP (epoxy resin); built in lightning protection Rotational speed Variable, 6-21 rpm Pitch Control Enercon single blade pitch system; one

independent pitch system per rotor blade with allocated emergency supply

Generator Enercon direct drive annular generator Brake Systems - 3 independent pitch control systems

- Rotor brake - Rotor lock

Yaw System Active via yaw gear, load dependent damping Cut out wind speed 28-34m/s

9 Sectoral scopes related approved methodologies and DOEs: http://cdm.unfccc.int/DOE/scopes.html

10 Gold Standard Toolkit, Chapter 1.2, p 20: http://www.cdmgoldstandard.org/fileadmin/editors/files/6_GS_technical_docs/GSv2/GSV2_Toolkit.pdf



A.4.4. Estimated amount of emission reductions over the chosen crediting period: >> Years Annual estimation of emission

reductions in tonnes of tCO2-eq

2012 14,36511 2013 34,477 2014 34,477 2015 34,477 2016 34,477 2017 34,477 2018 34,477

2019 20,11112 Total emission reductions (tonnes of CO2-eq) 241,338

Total number of crediting years 7 Annual average over the crediting period of estimated reductions (tonnes of CO2-eq)

34,477

A.4.5. Public funding of the project activity:

>> No public funding from the Annex I countries is provided to the proposed project.

11 It is estimated that the crediting period will start on 01.08.2012

12 It is estimated that the first crediting period will end on 01.08.2019



SECTION B. Application of a baseline and monitoring methodology

B.1. Title and reference of the approved baseline and monitoring methodology applied to the

project activity:

>> Applied approved baseline and monitoring methodologies:

• Approved consolidated baseline methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources”, version 12.1.0

Used tools:

• “Tool for the demonstration and assessment of additionality”, version 5.2.1 • “Tool to calculate the emission factor for an electricity system”, version 2.2.0

For more information regarding the methodology please refer to http://cdm.unfccc.int/methodologies/PAmethodologies/approved.html

B.2. Justification of the choice of the methodology and why it is applicable to the project

activity:

>> The project activity involves capacity addition by installation of new wind turbines additional to the existing power plant and units. The existing power plant/units will continue to operate after the implementation of the proposed project activity. The applicability of the methodology and tools have been discussed below. Applicability of ACM0002 version 12.1.0

The methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” 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 implementation of the project activity (greenfield); b) involve a capacity addition c) involve a retrofit of (an) existing plant(s); or d) involve a replacement of (an) existing plant(s). Since the proposed project activity involves grid connected renewable power generation that involve a capacity addition, ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” version 12.1.0 is applicable. The applicability criteria and conditions are discussed in more detail as follows: Ref. Applicability Criteria Justification

A) The project activity is the installation, capacity addition, retrofit or replacement of 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

The project activity involves capacity addition of an existing power plant by installation of new wind power units. The existing power plant is currently in operation with 34.2 MW and the capacity will reach approximately 54.2 MW with an addition of 10 new wind turbine units.



power plant/unit;

B) In case of capacity additions, retrofits or replacements (except for wind, solar wave and tidal power capacity addition projects which use Option 2 to calculate the parameter EGPJ,y): the existing plant started commercial operation prior to the start of minimum historical reference period of five years, used for the calculation of baseline emissions and defined in the baseline section, and no capacity expansion or retrofit of the plant has been undertaken between the start of this minimum historical reference period and the implementation of the project activity.

The proposed project activity involves wind power capacity addition and use Option 2 for the calculation of EGPJ,y, where EGPJ,y = EGPJ_ADD,y.

C) In case of hydro power plants, one of the following conditions apply:

- The project activity is implemented in an existing reservoir, with no change in the volume of reservoir; or

- The project activity is implemented in an existing reservoir, where the volume of reservoir is increased and the power density of the project activity, as per definitions given in the Project Emissions sections under the methodology, is greater than 4W/m2; or

- The project activity result in new reservoirs and the power density of the power plant, as per definitions given in the Project Emissions sections under the methodology, is greater than 4W/m2.

Since the proposed project is the capacity addition to a wind power plant, this criteria is not applicable to the proposed project activity.

D) The methodology is not applicable to the following:

- Project activities that involve switching from fossil fuels to renewable energy resources at the site of project activity, since in this case the baseline may be the continued us use of fossil fuels at the site;

- Biomass fired power plants; - Hydro power plants that result in

new reservoirs or increase in

The proposed project is the capacity addition to a wind power plant and not involving switching from fossil fuels to renewable energy resources neither involved in biomass fired power plants.



existing reservoirs where the power density of the power plant is less than 4W/m2.

Based on the above arguments it could be concluded that the methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” version 12.1.0 is applicable to the proposed project activity. In addition, the methodologies also refer to several tools described under section B.1 “Title and reference of the approved baseline and monitoring methodology applied to the project activity”. The applicability of these tools has been discussed below: Applicability of “Tool for the demonstration and assessment of additionality” v 05.2:

The tool for demonstration and assessment of additionality provides a general framework demonstrating and assessing additionality and is applicable to a wide range of project types. As referred in ACM0002, the additionality tool is applicable for the proposed project activity. Applicability of “Tool to calculate the emission factor for an electricity system” v 02.2:

This methodological tool determines the CO2 emission factor for displacement of electricity generated by power plants in an electricity system, by calculating the “combined margin” emission factor (CM) of the electricity system. This tool maybe applied to estimate the OM, BM and/or CM when calculating baseline emissions for a project activity that substitutes grid electricity. As the proposed project activity supplies electricity to the national grid, the “Tool to calculate the emission factor for an electricity system” v 02.2 is applicable to the project activity.

B.3. Description of the sources and gases included in the project boundary: >> Spatial Boundary: As per ACM0002 version 12.1.0, the spatial extent of the proposed project boundary includes the project power plant and all power plants connected physically to the electricity system, which the proposed project activity is connected to13.

Emission Sources: The greenhouse gases and emission sources included in or excluded from the project boundary are shown in Table 2 as followed:

Table 3 Emission sources included in or excluded from the project boundary

Source Gas Included? Justification/Explanation

Baseline CO2 emissions from electricity generation in fossil fuel fired power plants that are displaced

CO2 Yes Main emission source CH4 No Minor emission source N2O No Minor emission source

13 Reference: Turkish National Grid Line Diagram http://www.teias.gov.tr/4grupmd/atcharita.htm



due to the project activity.

Project activity For geothermal power plants, fugitive emissions of CH4 and CO2 from non-condensable gases contained in geothermal steam.

CO2 No Since the proposed project activity involves energy generation from wind energy, project emissions from project activity is assumed to be zero. This is also in line with the requirements of ACM0002 (version 12.1.0)

CH4 No

N2O No

CO2 emissions from combustion of fossil fuels from electricity generation in solar thermal power plants and geothermal power plants

CO2 No

CH4 No

N2O No

For hydro power plants, emissions of CH4 from the reservoir

CO2 No

CH4 No

N2O No

Figure 2: Project Boundary

Existing Power Plant

34.2 MW

Capacity Addition (Proposed Project

Activity) 20 MW

Private Electricity

Meter

Private Electricity

Meter

TEIAS Electricity

Meter

Akhisar Transformer

Station

Electricity System

Project Boundary



B.4. Description of how the baseline scenario is identified and description of the identified

baseline scenario:

>> The proposed project activity is a capacity addition to an existing grid-connected renewable power plant/unit. The baseline scenario in accordance with ACM0002 v12.1.0 is defined as followed: In the absence of the proposed VER project activity, the existing facility will continue to supply electricity to the grid at historical levels. Since the project activity is based on wind energy and Option 2 is chosen for the determination of EGPJ,y, the baseline scenario for the proposed project is the equivalent annual net electricity generation supplied to the grid by the power units that have been added under the project activity. B.5. Description of how the anthropogenic emissions of GHG by sources are reduced below

those that would have occurred in the absence of the registered CDM project activity (assessment

and demonstration of additionality): >>

Timeline of the Project:

An overview of the implementation time line of the proposed project is presented in table 3 as followed: Table 4 Timeline of the proposed project activity

Event Actual / Expected Date

Revision of the Generation License Actual 08.04.2010 Board Decision on VER Project Development

Actual 15.01.2010

Local Stakeholders Meeting Actual 06.06.2011 Turbine Purchase Contract Expected Q4 2011 Start of Construction Expected Q4 2011 Project Commissioning Expected Q3 2012 Based on the events listed above, the project entity has been aware of the VER and the decision was based on VER revenues taken into account. The potential carbon revenue was vital for the project owner to go ahead with the implementation of the proposed project activity. Approved consolidated baseline methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” version 12.1.0, requires the use of the latest “Tool for demonstration and assessment of additionality” (v05.2.1) agreed by the CDM Executive Board to demonstrate and assess the additionality of the proposed project. The tool provides for a step-wise approach to demonstrate and assess additionality. These steps include:

• Identification of alternatives to the project activity; • Investment analysis to determine that the proposed project activity is either 1) not the most

economical or financial attractive, or 2) not economically or financially feasible; • Barrier analyses; and • Common practice analysis.



Step 1. Identification of alternatives to the project activity consistent with current laws and

regulations

According to CDM Validation and Verification Manual14 (version 01.2), the PDD shall identify credible alternatives to the project activity in order to determine the most realistic baseline scenario, unless the approved methodology that is selected by the proposed CDM project activity prescribes the baseline scenario and no further analysis is required. Alternatives to the proposed project is not needed to be identified as the baseline scenario has been prescribed according to ACM0002 (v12.1.0) under section B.4. Step 2. Investment analysis

According to “Tool for the demonstration and assessment of additionality” version 5.2.1, the economical or financial attractiveness of the proposed project should be determined without taking into consideration the VER revenues. It should be noted that the guidance provided by the Executive Board on investment analysis has been taken into account15. The following sub-steps are conducted in order to do the investment analysis.

Sub-step 2a. Determination of an appropriate analysis method:

According to “Tool for the demonstration and assessment of additionality” version 5.2.1, simple cost analysis can only be applied to projects that do not generate any other financial benefits than the VER related incomes. Considering that the electricity produced by the proposed project will be sold to the national grid and is expected to create revenues, the simple cost analysis is discarded. A benchmark analysis (option III) has been chosen as the appropriate analysis method. Sub-step 2b. Option III. Apply benchmark analysis

The following benchmark analysis applies the equity IRR as financial indicator. The Equity IRR is considered to be a suitable and widely used financial indicator to determine the attractiveness of equity investments. When analysing a potential project, investors compare the equity IRR of the project against their required rate of return. The approach to determine the benchmark against which the equity IRR shall be evaluated is option (a) from the “Tool for the demonstration and assessment of additionality” (Version 05.2.1): "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; ..."

14 Reference: CDM Validation and Verification Manual, page 20 paragraph 105

15 Reference: “Guidelines on The Assessment of Investment Analysis” version 3, EB 51 Annex 58.



In line with the requirements of “Tool for the demonstration and assessment of additionality” (Version 05.2.1) and its supporting guidelines, the expected return on equity is calculated based on; risk free rate, equity risk premium and the country risk premium. Risk Free Rate: The risk free rate of return is the best rate that does not involve a risk. Both the return of the original capital and the payment of interest are completely certain. Government bonds are considered a risk free investment option, and their yields can be seen as a risk free rate of return. TCMB (Central Bank of Turkey) publishes Financial Stability Report periodically, which also includes data on long term bond rates. The latest and most up to date report is from March 2011. According to the official report the bond rates are 6.5%16. Equity Risk Premium: The equity risk premium is the historical risk premium for a mature equity market. The US stock return over a long term provides the most ideal figure since this is by far the largest and most liquid market and one which provides data over the longest term. A value of 6.5% is used for the equity risk premium17. Country Risk Premium: The risk premium for the host country is derived from Moody’s rating for Turkey. Turkey has a long-term rating of Ba2 which corresponds to a country risk premium of 4.1%18. Based on the above data set the required rate of return could be calculated as 17.1% for Turkey. Table 6 Benchmark for Turkey Parameter Value

Risk Free Rate 6.5% Equity Risk Premium 6.5% Country Risk Premium

4.1%

Required Rate of Return

17.1%

16 Reference: TCMB Financial Stability Report March 2011 Section II page 16 http://www.tcmb.gov.tr/yeni/evds/yayin/finist/bolumII-12.pdf

17 Reference: Guidelines on the assessment of investment analysis version 5 http://cdm.unfccc.int/Reference/Guidclarif/reg/reg_guid03.pdf

18 Reference: New York University Stern School of Business, Risk Premiums for other markets July 2011 http://www.stern.nyu.edu/~adamodar/pc/datasets/ctrypremjuly11.xls



Sub-step 2c: Calculation and comparison of financial indicators

The main financial indicators are presented in the below table: Table 5 Key parameters applied in the calculation of the proposed project’s equity IRR: Parameter Unit Value

Total investment € 24,000,000 Loan % 85 Equity % 15 General Overheads € / year average 900,000 Yearly electricity Generation GWh/year 55 Installed capacity MW 20 Electricity feed in tariff €cent/kWh 5.07 €cent/kWh Corporate Tax % 20

The key assumptions for the calculation of the equity IRR are as follows:

- The calculation of the equity IRR of the proposed project activity includes all relevant costs and revenues19.

- The revenue from yearly electricity generation is based on the guaranteed feed in tariff applicable at the time of the investment decision20. According to the Law, the guaranteed feed in tariff for electricity generated from wind energy is 7.3 USDcent/kWh, which corresponds to approximately 5 €cent/kWh21 for the first 10 year period. For the remaining years a conservative market price of 6€cent/kWh has been applied.

- Input values used in the investment analysis are values valid and applicable for 2011. - Only the portion of investment costs which is financed by equity have been considered as the net

cash outflow and the portion of the investment cost which is financed by dept have not been considered as a cash outflow.

- 8 €/tCO2eq value has been taken for the GS VER credits, which is an average price for the GS VERs in the market.

The result of the equity IRR calculation with and without VER revenues are: Equity IRR without VERs -12% Equity IRR with VERs -2%

It could be seen that the equity IRR of the project activity is below the financial benchmark of 17.1 % and cannot be considered to be a financially attractive alternative. With the introduction of expected revenues from VERs, although the equity IRR is still below the benchmark, the feasibility is increases, which has a positive impact on access to finance and has been the bases of the investment decision.

19The full financial calculation is available to the DOE.

20 Reference: EMRA (Electricity Market Regulatory Authority) Law on Utilization of Renewable Energy Resources http://www.epdk.gov.tr/documents/10157/4b360128-53aa-4174-8104-a6c10434ac9c

21 As per 09.09.2011, the euro/dollar exchange rate is observed to fluctuate between 1.43 and 1.45 for the past three months. An average exchange rate of 1.44 €/USD has been used. Reference: Central Bank of Republic of Turkey http://www.tcmb.gov.tr/



Sub-step 2d: Sensitivity Analysis

The objective of the sensitivity analysis is to show whether the conclusion regarding the financial attractiveness is robust to reasonable variations in the critical assumptions. According to the Annex 5 of EB 62 “Guidelines on the assessment of Investment analysis” version 5, only variables including the initial investment cost, that constitute more than 20% of either total project costs or total project revenues should be subjected to reasonable variation. In line with the guidelines, important parameters for the feasibility of the proposed project activity are defined as total investment, electricity price, electricity generation and general overheads. The mentioned parameters have been tested with a range of ±10% for the sensitivity analysis. The following table demonstrates the results for a ±10% deviation of selected parameters which increase the equity IRR. Table 6 Sensitivity Analysis of the equity IRR with variations in total investment, electricity price, electricity generation, investment and general overheads. Parameter Value Applied Equity IRR

Reached

Without VER

Equity IRR

Reached

WithVER Electricity Price 8,03 USDcent/kWh (+10%) 2% 8% Electricity

Generation

60,500 MWh/year (+10%) -4% 5%

General Overheads 794,000 €/year average (-10%) -9% 0% Total investment 21.6 million € (-10%) -6% 4% Discussion on the probability of the deviations: Electricity Price: One of the most important parameter that has an impact to the equity IRR of the project is the electricity sales price. For the sensitivity analysis the electricity price was increased 10% from the guaranteed price of 7,3 to 8,03 USDcent/kWh for the whole assessment period and observed that the equity IRR reaches to 2% without taking into the VER revenues and to 8% taking into account the VER revenues, which is still below the benchmark value. The Law on Utilization of Renewable Energy Resources, provides a guaranteed electricity tariff of 7.3 USDcent/kWh to the electricity generated from wind energy resources, which is applicable for a 10 year period. In addition to this guaranteed price, the Law also introduces an additional incentive to projects benefiting from local equipment in their project activity. According to the Law, wind energy projects using local equipment could be rewarded by a plus incentive as indicated under Table II of the Law on top of the guaranteed price of 7,3 USDcent/kWh. Although it is not for certain that the proposed project will be eligible for this plus incentive, since the blades and turbine masts used in the proposed project activity are produced locally, the project activity has a significant chance to be rewarded a +1.4



USDcent/kWh22. This plus incentive will be applicable only for a 5 year period. If this would be the case the electricity tariff applicable to the project activity for the first 5 years will be 8.7 USDcent/kWh. If the equity IRR calculation is re-executed for this price the equity IRR reaches to -9%, which is within the sensitivity range. Electricity Generation: Another important parameter that has an impact on the equity IRR is the net electricity generation delivered to the electricity system. For the sensitivity analysis, the electricity generation is increased by 10% from the value of 55GWh/year to 60.5GWh/year and observed that the equity IRR reaches to -4% without taking into the VER revenues and to 5% taking into account the VER revenues, which is still below the benchmark value. It should be noted that the equity IRR doesn’t reach to the benchmark even with a net electricity generation of 74.25GWh/year, which corresponds to a 35% of increase. An average annual electricity generation of 55GWh/year has been estimated based on micro-siting23, which corresponds to a load factor of 31,4%. Since the existing capacity of 34.2 MW is operational since 2008, an accurate performance of the project location is known to the Project Participant. The actual readings indicate a capacity factor of approximately 27% load factor for the project and therefore an increase over 35% of the expected generation (corresponding to a load factor of 42%) is not realistic. General Overheads: The impact of a deviation in general overheads is relatively insignificant compared to changes in other parameters. For the sensitivity analysis, the general overheads are decreased by 10% from the value of approximately 900,000 €/year average to approximately 794,000 €/year average and observed that the equity IRR reaches to -9% without taking into the VER revenues and to 0% taking into account the VER revenues, which is still below the benchmark value. Even if the general overheads are considered to be “0”, the equity IRR does not reach to the benchmark. Total Investment: For the sensitivity analysis, the total investment costs are decreased by 10% from the value of 24 million € to 21.6 million € (approximately 1 million €/MW) and observed that the equity IRR reaches to -6% without taking into the VER revenues and to 4% taking into account the VER revenues, which is still below the benchmark value. The equity IRR cannot even reach to the benchmark when the total investment is considered to be as low as 16.8 million €s, which is 30% lower than the estimated investment. Taking into account the fact that the investment cost of an average turbine is 1.23 million/MW24, a major deviation from the estimated investment costs is not realistic.

22 According to Table II of the Law on Utilization of Renewable Energy Resources, +0.8 USDcent/kWh is rewarded for locally produced turbine blades and +0.6 USDcent/kWh is rewarded for locally produced turbine masts.

23 Technical feasibility is available to the DOE.

24 Reference: EWEA (European Wind Energy Association) “Wind Energy –The Facts Report, page 13 Part III, The Economics of Wind Power. http://www.ewea.org/fileadmin/ewea_documents/documents/publications/WETF/1565_ExSum_ENG.pdf



Outcome of Step2: The sensitivity analysis shows that the equity IRR of the proposed project does not overcome the financial benchmark despite favourable conditions. The sensitivity analysis further substantiates that the project activity is not a financially attractive alternative and therefore additional. Step 3. Barrier analysis

Sub-step 3a. Identify barriers that would prevent the implementation of the proposed CDM project

activity:

Without being registered as a VER project, the proposed project activity faces barriers that would prevent its implementation. The main barrier towards the implementation of the project activity could be characterized as “limited access to financing” due to unfavourable investment and financial structure which results in high risks and limited access to project financing. Limited access to project financing:

Waste management projects need a high level of financing and long repayment periods. In the proposed project activity, it is envisaged that 85% of the investment will be realised with debt funding and 15% from equity. However the project participants face barriers to secure loan from finance institutions / creditor banks. The additional revenues from potential VER sales are considered to be an important revenue stream and play an important role on securing a debt funding. Wind energy investments are still perceived as investments with high risks and unfavourable investment and finance structure. Although there is a guaranteed electricity tariff for wind energy in Turkey, it is still not enough to secure an attractive feasibility and therefore extra revenues such as VERs are considered to have a positive impact on the bankability of the project from the creditors point of view. Outcome of Step 3a:

“Investment Barriers” is identified as one of the major barriers that prevent the Project Participant from carrying out the proposed project activity Step 4: Common practice analysis

Sub-step 4 a: Analyse other activities similar to the proposed project activity:

As per the “Tool for the demonstration and assessment of the additionality” version 5.2.1, an analysis of any other activities that are operational and that are similar to the proposed project activity must be provided. Projects are considered similar if they are in the same country/region and/or rely on a broadly similar technology, are of similar scale, and take place in a comparable environment with respect to regulatory framework, investment climate, access to technology, access to financing, etc. The project activities have been tracked from EMRA (Electricity Market Regulatory Authority) Generation Licenses25. Currently there are 41 wind farm projects that are connected and operational in

25 Reference: EMRA / Development of Wind Energy in Turkey http://www2.epdk.org.tr/lisans/elektrik/yek/ruzgarprojeleriningelisimi.xls



Turkey26. The total installed capacity reaches to 1493 MW, which constitutes less than 3% of the total installed capacity of Turkey27. A list of the operational wind farms are presented below: Table 8. Operation wind farms in Turkey

# Location Company Installed

Capacity

(MW)

Business

Model28

1 Đzmir - Çeşme Alize Enerji Elektrik Üretim A.Ş.

1.5 BOT

2 Çanakkale - Đntepe Anemon Enerji Elektrik Üretim A.Ş.

30.4 VER

3 Manisa - Akhisar Deniz Elektrik Üretim Ltd. Şti

10.8 VER

4 Çanakkale - Gelibolu Doğal Enerji Elektrik Üretim A.Ş.

14.9 VER

5 Manisa - Sayalar Doğal Enerji Elektrik Üretim A.Ş.

34.2 VER

6 Đstanbul – Çatalca Ertürk Elektrik Üretim A.Ş. 60 VER 7 Izmir - Aliağa Innores Elektrik Üretim A.Ş. 42.5 VER 8 Istanbul - Gaziosmanpaşa Lodos Elektrik Üretim A.Ş. 24 VER 9 Izmir - Çeşme Mare Manastır Rüzgar

Enerjisi Santrali San. Ve Tic. A.Ş.

39.2 VER

10 Istanbul - Hadımköy Sunjüt Sun’i Jüt San. ve Tic. A.Ş

1.2 BOT

11 Đstanbul - Silivri Teperes Elektrik Üretim A.Ş. 0,85 VER 12 Balikesir - Bandırma Yapısan Elektrik Üretim A.Ş. 30 VER 13 Balikesir - Şamlı Baki Elektrik Üretim Ltd Şti 90 VER 14 Muğla - Datça Dares Datça Rüzgar Enerji

Santralı Sanayi ve Ticaret A.Ş 29.6 VER

15 Hatay - Samandağ Deniz Elektrik Üretim A.Ş. 30 VER 16 Aydın - Didim Ayen Enerji A.Ş. 31.5 VER 17 Çanakkale - Ezine Alize Enerji Elektrik Üretim

A.Ş. 20.8 VER

18 Balikesir - Susurluk Alize Enerji Elektrik Üretim A.Ş.

20.7 VER

19 Osmaniye - Bahçe Rotor Elektrik Üretim A.Ş. 135 VER 20 Izmir Bergama Ütopya Elektrik Üretim

Sanayi ve Ticaret A.Ş. 30 VER

21 Đzmir - Çeşme Mazı-3 Rüzgar Enerjisi Santrali Elektrik Üretim A.Ş.

30 VER

22 Balıkesir - Bandırma Akenerji Elektrik Üretim A.Ş. 15 VER 23 Balikesir - Bandırma Borasco Enerji ve Kimya 57 VER

26 As per 17.08.2011.

27 The total installed capacity of Turkey is 44,761 MW for year 2009. Reference: TEIAS (Turkish Electricity Transmission CO) Annual development of Turkeys Installed capacity 2009 http://www.teias.gov.tr/istatistik2009/1.xls

28 Reference: Gold Standard Foundation VER Project Registry Page https://gs1.apx.com/myModule/rpt/myrpt.asp?r=111



Sanayi ve Ticaret A.Ş.

24 Manisa - Soma Soma Enerji Elektrik Üretim A.Ş.

79.2 VER

25 Hatay - Belen Belen Elektrik Üretim A.Ş. 36 VER 26 Tekirdağ - Şarköy Alize Enerji Elektrik Üretim

A.Ş. 28.8 VER

27 Izmir – Urla Kores Kocadağ Rüzgar Enerji Santralı Üretim A.Ş.

15 VER

28 Balıkesir - Bandırma As Makinsan Temiz Enerji Elektrik Üretim San. ve Tic. A.Ş.

24 VER

29 Mersin Mut Akdeniz Elektrik Üretim A.Ş. 33 VER 30 Edirne - Enez Boreas Enerji Üretim

Sistemleri A.Ş. 15 VER

31 Izmir - Bergama Bergama RES Enerji Üretim A.Ş.

90 VER

32 Hatay - Belen Bakras Enerji Elektrik Üretim ve Tic. A.Ş.

15 VER

33 Hatay - Samandağ Ziyaret RES Elektrik Üretim San. ve Tic. A.Ş.

35 VER

34 Manisa - Soma Bilgin Rüzgar Santrali Enerji Üretim A.Ş.

90 VER

35 Manisa – Kırkağaç Alize Enerji Elektrik Üretim A.Ş.

25.6 VER

36 Çanakkale - Ezine Garet Enerji Üretim ve Ticaret A.Ş.

22.5 VER

37 Aydin - Çine Sabaş Elektrik Üretim A.Ş. 24 VER 38 Çanakkale - Ezine Enerjisa Enerji Üretim A.Ş. 29.9 VER 39 Balikesir - Susurluk Alentek Enerji A.Ş. 45 VER 40 Balikesir – Havran Alize Enerji Elektrik Üretim

A.Ş. 16 VER

41 Balikesir - Bandırma Galata Wind Enerji Ltd. Şti 90 VER

TOTAL 1493.15

In line with the requirements of the “Tool for the demonstration and assessment of the additionality” version 5.2.1, the following scope of assessment has been applied in selecting the “similar project activities”:

- Turkey as the geographical scope - Project activities with an installed capacity over 2 MW (project activities with an installed

capacity smaller than 2 MW could be considered as pilot or demo project since it only involves 1 or 2 turbine units)

- In line with the requirements of the tool, VER project activities will be excluded from the common practice analysis29.

Based on the above information it is clear that there are no similar project activities in Turkey, which are not developed with a business model excluding VER revenues, hence it can be concluded that wind projects are not a common practice and the technology has not yet diffused in Turkey.

29 The term CDM and UNFCCC under the tool is interpreteed as VER and Gold Standard respectively (Sub step 4a: Analyze other activities similar to the proposed Project activity).



Substep 4 b: Discuss any similar options that are occurring:

There are no similar options occurring which do not rely on VER revenues for their implementation. The proposed project activity is therefore not common practice and hence proves to be additional. B.6. Emission reductions:

B.6.1. Explanation of methodological choices: >> The emission reductions for the proposed project activity are calculated according to ACM0002 “Consolidated baseline methodology for grid connected electricity generation from renewable sources” version 12.1.0. Emission Reductions

The emission reductions are calculated based on the following formula:

YYy PEBEER −= (1)

Where: ERy Emission reductions in year y (tCO2e/year) BEy Baseline emissions in year y (tCO2e/year) PEy Project emissions in year y (tCO2e/year)

Project Emissions

In accordance with the methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0), no project emissions need to be considered. Project emissions apply only for geothermal power plants, solar thermal power plants and for some hydro power plants. Therefore PEy = 0 Baseline Emissions

According to the methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0), baseline emissions include only CO2 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 calculated as follows:

CMgridyPJy EFEGBE ,, ⋅= (2)

Where:



Calculation of EGPJ,y

The calculation of EGPJ,y is different for (a) greenfield plants; (b) retrofits and replacements and; (c) capacity additions. Since the proposed project activity falls under the description capacity addition, the following method has been adopted. Capacity addition to an existing renewable energy power plant

In case of wind energy, it is assumed that the addition of new capacity does not significantly affect the electricity generated by existing power plant(s) or unit(s). In this case, the electricity fed into the grid by the added power plant(s) or unit(s) could be directly metered and used to determine EGPJ,y. If the project activity is a capacity addition, project participants may use one of the following options to determine EGPJ,y: Option 1: Use the approach applied to retrofits and replacements as described in the ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0). EGFacility,y corresponds to the total electricity generation of the existing plant(s) or unit(s) and the added plant(s) and unit(s). A separate metering of the electricity fed into the grid by the added plant(s) or unit(s) is not necessary under this option. Option 2: For wind, solar, wave and tidal power plant(s) or unit(s), the following approach can be used provided that the electricity fed into the grid by the added power plant(s) or unit(s) addition is separately measured:

yADDPJyPJ EGEG ,_, = (3)

Where: EGPJ,y Quantity of net electricity generation that is produced and fed into the grid as a result

of the implementation of the VER project activity in year y (MWh/yr) EGPJ_ADD,y Quantity of net electricity generation supplied to the grid in year y by the project

plant/unit that has been added under the project activity (MWh/yr) The Project Participants choose Option 2, and the electricity fed into the grid by the added power plant(s) or unit(s) addition will be separately measured.

BEy = Baseline emissions in year y (tCO2/year) EG PJ,y = Quantity of net electricity generation that is produced and fed into the grid as a result of

the implementation of the CDM project activity in year y (MWh/yr) EFgrid,CM = Combined margin CO2 emission factor for grid connected power generation calculated

using the latest version of the “Tool to calculate the emission factor for an electricity system”. The combined margin is calculated ex-post and has been fixed for the first crediting period.



Leakage

In line with the requirements of ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0), no leakage emissions are considered. The main emissions potentially giving rise to leakage in context of electric sector projects are emissions arising due to activities such as power plant construction and upstream emissions from fossil fuel use (e.g. extraction, processing and transport). These emission sources are neglected. Calculation of EFgrid,CM

As referred in ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0), EFgrid,CM is calculated according to the “Tool to calculate the emission factor for an electricity system” version 02.2.0. This tool provides the following steps to calculate combined margin (CM) emission factor: Step 1. Identify the relevant electric systems; Step 2. Choose whether to include off-grid power plants in the project electricity system (optional); Step 3. Select an operating margin (OM) method; Step 4. Calculate the operating margin emission factor according to the selected method; Step 5. Calculate the build margin (BM) emission factor. Step 6. Calculate the combined margin (CM) emissions factor. Step 1. Identification of the relevant electric power system

According to the “Tool to calculate the emission factor for an electricity system” (version 02.2), a project electricity system has to be defined by the spatial extent of the power plants that are physically connected through transmission and distribution lines to the project activity and that can be dispatched without significant transmission constraints.

Similarly, a connected electricity system, e.g. national or international, is defined as 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.

The transmission lines in Turkey are operated by TEĐAŞ (Turkish Electricity Transmission CO), which is a state owned company. The grid is 48.971 km long and constitutes of 606 transformer stations with a total transformer capacity of 98,852 MVA and 10 interconnections to neighbour countries30. The interconnected grid system is operated continuously and there are no electricity price differences throughout the regions31. Therefore the relevant electric power system is defined as the national grid system of Turkey.

30 In compliance with the requirements of the applicable tool, the emission factor from neighbouring countries is considered 0 tCO2eq/MWh for determining the OM.

31 Reference: TEIAŞ (Turkish Electricity Transmission Co) official webpage http://www.teias.gov.tr/



Step 2. Choose whether to include off-grid power plants in the project electricity system (optional).

According to the applicable tool, Project Participants may choose between the following two options to calculate the operating margin and build margin emission factor: Option I: Only grid power plants are included in the calculation. Option II: Both grid power plants and off-grid power plants are included in the calculation. The Project Participant chooses Option I and therefore only grid power plants are included in the calculation. Step 3. Selection of an operating margin (OM) method

According to the applicable methodological tool, the operating margin emission factor (EF grid, OM, y) is based on one of the following methods: a) Simple OM; or b) Simple adjusted OM; or c) Dispatch data analysis OM; or d) Average OM. Options b) and c) are not selected since there is no data available for these options. Option d) is not selected since low-cost/must-run resources do not constitute more than 50% of total grid generation. According to the tool, Simple OM can only be if low-cost/must-run resources constitute less than 50% of total grid generation. The low-cost/must-run resources include hydro, geothermal, wind, low-cost biomass, nuclear, and solar power generation. The share of the installed capacity of renewable energy sources excluding hydro power is 1.1% of the total electricity generation and is therefore not taken into consideration. There is no indication that coal is used as a must-run and no nuclear energy plants are located in Turkey. That leaves hydro power as the only relevant low-cost must run source for electricity. The electricity generation from hydro power is 18.5% of the total electricity generation. Therefore the requirements for the use of the Simple OM calculations are satisfied. Table 9 Breakdown by sources of the electricity generation from the Turkish grid, 200932

Power plants by fuel type 2009 Generation

Generation (MWh) Share (%)

Natural Gas 96,094,700 49.3 Coal 55,685,100 28.6 Hydro power 35,958,400 18.5 Fuel Oil 4,803,500 2.5 Geothermal + Wind 1,931,100 1 Other Renewable 340,100 0.1 Total 194,812,900 100

32 TEIAS (Turkish Electricity Transmission Company) 2009: http://www.teias.gov.tr/istatistik2009/32(75-09).xls



For the simple OM, the emissions factor can be calculated using either of the two following data vintages:

• 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 a 3-year generation-weighted average, based on the most recent data available at the time of submission of the VER-PDD to the DOE for validation.

• Ex post option: If the ex post option is chosen, the emission factor is determined for the year in which the project activity displaces grid electricity, requiring the emissions factor to be updated annually during monitoring. For the proposed project activity the ex ante option is selected. Data for calculating the three year average is obtained from the period 2007 – 2009 which are the most recent data available at the time of submission of the PDD to DOE.33 Step 4. Calculating the operating margin emission factor according to the selected method

The simple OM emission factor is calculated as the generation-weighted average CO2 emissions per unit

net electricity generation (tCO2e/MWh) of all generating power plants serving the system, not including low-cost / must-run power plants / units. It may be calculated: Option A: Based on the net electricity generation and a CO2 emission factor of each power unit; or Option B: Based on the total net electricity generation of all power plants serving the system and the fuel types and total fuel consumption of the project electricity system. As the fuel consumption and the average efficiency data for each power plant / unit is not available Option B is used for simple OM calculation.34 Option B: Calculation based on total fuel consumption and electricity generation of the system

As Option B is used, 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:

2, , , ,

, ,

i y i y CO i y

igrid OMsimple y

y

FC NCV EF

EFEG

× ×∑

(4)

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

33 The index “y” in the equations refers to the years 2007-2009 to calculate the emission factor ex-ante.

34 There are no nuclear power plants in Turkey and the share of the renewable energy is very small.



or volume unit)

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

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

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

year y y The three most recent years for which data is available at the time of submission of the

PDD to the DOE for validation (ex-ante option) For this approach (simple OM) to calculate the operating margin, subscript m refers to the power plants/units delivering electricity to the grid, not including low-cost/must run power plants/units, and including electricity imports to the grid. Step5. Calculation of the build margin emission factor

In terms of vintage of data, project participants can choose between one of the following two options: Option 1: For the first crediting period, calculate the build margin emission factor ex ante based on the most recent information available on units already built for sample group m at the time of VER PDD submission to the DOE for validation. For the second crediting period, the build margin emission factor should be updated based on the most recent information available on units already built at the time of submission of the request for renewal of the crediting period to the DOE. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. This option does not require monitoring the emission factor during the crediting period. Option 2: For the first crediting period, the build margin emission factor shall be updated annually, ex post, including those units built up to the year of registration of the project activity or, if information up to the year of registration is not yet available, including those units built up at the latest year for which information is available. For the second crediting period, the built margin emission factor shall be calculated ex ante, as described in Option 1 above. For the third crediting period, the built margin emission factor calculated for the second crediting period should be used. For the proposed project activity the Project Participant chooses Option 1 in terms of vintage of data.

The sample group of power units m used to calculate the build margin should be determined as per the following procedure, consistent with the data vintage selected above:

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

(b) Determine the annual electricity generation of the project electricity system, excluding power units registered as VER project activities (AEGtotal, in MWh). Identify the set of power units, excluding power units registered as VER project activities, that started to supply electricity to the grid most recently and that comprise 20% of total AEGtotal (if 20% falls on part of the generation



of a unit, the generation of that unit is fully included in the calculation) (SET>20%) and determine their annual electricity generation (AEGSET>20%, in MWh);

(c) From SET5-units and SET>20% select the set of power units that comprise the larger annual electricity generation (SETsample); Identify the date when the power units in SETsample started to supply electricity to the grid. If none of the power units in SETsample started to supply electricity to the grid more than 10 years ago, then use the SETsample to calculate the build margin.

The most recent information available belongs to 2009 and based on TEIAŞ statistics which is the official information source for the grid35. According to TEIAŞ figure, the annual electricity generation of the project electricity system excluding power units registered as VER project activities (AEGtotal) is 194,912,900 MWh36. Based on the AEGtotal, the set of power units, excluding power units registered as VER project activities, that started to supply electricity to the grid most recently and that comprise 20% of total AEGtotal, have been defined and the AEGSET>20% is determined as 39,022,327 MWh37 and includes 239 units of power plants under SET>20%. Without the need of any further assessment it can be concluded that the SET5-units << SET>20% and therefore the SET>20% is selected as SETsample

38 for the calculation of

the build margin (BM)39. The built margin (BM) emission factor is the generation-weighted average emission factor (tCO2/MWh) of all power units m during the most recent year y for which power generation data is available40, calculated as follows:

, , ,

, ,

,

m y EL m y

mgrid BM y

m y

m

EG EF

EFEG

×

=∑

∑ (5)

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

(MWh)

35 Reference: www.teias.gov.tr

36Reference: Turkish Electricity Transmission Co / http://www.teias.gov.tr/istatistik2009/41.xls

37 Reference: Turkish Electricity Transmission Company / http://www.teias.gov.tr/istatistikler.htm; year 2009-2008-2007-2006.

38 None of the power units in SETsample started to supply electricity to the grid more than 10 years ago.

39 Please refer to Annex 3 of the PDD for more detailed information on SETsample.

40 The most recent year for which power generation data is available is 2009. Reference: TEIAŞ Generation and Transmission Statistics www.teias.gov.tr



EFEL,m,y CO2 emission factor of the power unit m in year y (tCO2/MWh) m Power units included in the build margin y Most recent historical year for which power generation data is available

As per the “Tool to calculate the emission factor for an electricity system” (version 02.2.0), the CO2 emission factor of each power unit m (EFEL,m,y) should be determined as per the guidance from the tool in step 4 for simple OM, using options A1, A2 or A3, using for y the most recent historical year for which power generation data is available, where m is the power units included in the build margin. As plant specific fuel consumption data is not available for Turkey, option A2 has been selected for the calculation of the CO2 emission factor of each power unit m (EFEL,m,y) as follows:

ym

yiCO

ymEL

EFEF

,

,,

,,

6.32

η

⋅=

(6)

Where: EFELm,y CO2 emission factor of the power unit m in year y (tCO2/MWh) EFCO2,m,i,y Average CO2 emission factor of fuel type i used in power unit m in year y (tCO2/GJ) ηm,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 most recent year for which power generation data is available at the time of

submission of the VER-PDD to the DOE for validation (ex-ante option) Where several fuel types are used in the power unit, the lowest CO2 emission factor for EFCO2,m,i,y has been used. Step 6. Calculation of the combined margin emission factor

According to the applicable methodological tool, the calculation of the combined margin (CM) emission factor (EFgrid, CM) is based on one of the following methods:

(a) Weighted average CM; or (b) Simplified CM.

In line with the requirements of the applicable tool, the Project Participant chooses option (a), weighted average CM. The combined margin emissions factor is calculated as follows:

, , , , , ,grid CM y grid OM y OM grid BM y BMEF EF w EF w= ⋅ + ⋅(7)

Where: EFgrid,CM,y Combined Margin emission factor (tCO2/MWh) EFgrid,OM,y Operating margin emission factor (tCO2/MWh)



EFgrid,BM,y Build margin emission factor (tCO2/MWh) wOM Weight of the operating margin emission factor wBM Weight of the build margin emission factor

As stated in the “Tool to calculate the emission factor for an electricity system” (version 02.2.0), the default weights for the operating margin and build margin emission factors for wind power generation is defined as: wOM=0.75 wBM=0.25 for the first crediting period and for subsequent crediting periods. Changes required for the methodology implementation in 2

nd and 3

rd crediting periods

At the start of the second and third crediting period the Project Proponents will address two issues as required by the applicable methodology:

• Assess the continued validity of the baseline; and • Update the baseline as defined above

B.6.2. Data and parameters that are available at validation:

Data/ Parameter: ID.1 / EGgross

Data unit: MWh Description: Gross electricity production by fossil fuel power sources (2007-2009) Source of data used: TEIAS (Turkish Electricity Transmission Company)

The distribution of gross electricity generation by primary energy resources and the electricity utilities in Turkey (2007, 2008, 2009). http://www.teias.gov.tr/ist2007/40.xls http://www.teias.gov.tr/istatistik2008/41.xls http://www.teias.gov.tr/istatistik2009/37(06-09).xls

Value applied: See calculations of emission factor (B.6.1) Justification of the choice of data or description of measurement methods and procedures actually applied:

According to “Turkish Statistics Law and Official Statistics Program”41 TEIAS, the Turkish Electricity Transmission Company is the official source for the related data, hence providing the most up-to-date and accurate information available.

Any comment: The average correction factor between gross/net generation is 95.8%. Its determination is presented in the Ex-ante calculation sheets.

Data/ Parameter: ID.2 / FCi,y

Data unit: m3 / tonnes (m3 for gaseous fuels) Description: Amount of fossil fuel type i consumed in the project electricity system by

41 TEIAS 2005: http://rega.basbakanlik.gov.tr/Eskiler/2005/11/20051118-1.htm



generation sources in year y (2007-2009)

Source of data used: TEIAS (Turkish Electricity Transmission Company) Fuels consumed in thermal power plants in Turkey by the electricity utilities (2007-2009)


According to “Turkish Statistics Law and Official Statistics Program” TEIAS, the Turkish Electricity Transmission Company is the official source for the related data, hence providing the most up-to-date and accurate information available.

Any comment: -

Data/ Parameter: ID.3 / NCVi,y

Data unit: GJ/tonnes (m3 for gaseous fuels) Description: Net calorific value (energy content) of fossil fuel type i in year y Source of data used: TEIAS (Turkish Electricity Transmission Company)

Heating values of fuels consumed in thermal plants in Turkey by the electricity utilities (2007- 2009) http://www.teias.gov.tr/istatistik2009/46.xls


According to “Turkish Statistics Law and Official Statistics Program” TEIAS, Turkish Electricity Transmission Company is the official source for the related data, hence providing the most up-to-date and accurate information available

Any comment: -

Data/ Parameter: ID.4 / EFC02,i,y

Data unit: tCO2/GJ Description: CO2 emission factor of fossil fuel type i” used in power unit min year y Source of data used: IPCC default values at the lower limit of the uncertainty at a 95% confidence

interval as provided in table 1.4 of Chapter 1 of Volume 2 (Energy) of the 2006 IPCC Guidelines for National Greenhouse Gas Inventory http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.htm


There is no information on the fuel specific default emission factor in Turkey, hence, IPCC values has been used as referred in the “Tool to calculate the emission factor for an electricity system (version 2)”.

Any comment: -



Data/ Parameter: ID.5 / EGm,y

Data unit: MWh Description: Net electricity generated by power plant/unit m Source of data used: TEIAS (Turkish Electricity Transmission Company)

Generation units put into operation in 2006; 2007; 2008 http://www.teias.gov.tr/ist2006/8.xls, for 2006 http://www.teias.gov.tr/ist2007/8.xls, for 2007 http://www.teias.gov.tr/istatistik2008/8.xls, for 2008

Value applied: Annex 3 Justification of the choice of data or description of measurement methods and procedures actually applied:

Once for each crediting period using the most recent three historical years for which the data is available at the time of submission of the PDD to the DOE for validation.

Any comment: -

Data/ Parameter: ID.6 / η m,y

Data unit: % Description: Average net energy conversion efficiency of power unit m in year y Source of data used: “Environmental Map” published by Environmental Inventory Head Department

under Ministry of Environment and Forestry / http://www.cedgm.gov.tr/CED/Files/cevreatlas%C4%B1/atlas_metni.pdf (p.197 table X.3.1; Thermal Plants and Environment)


The average values of thermal plants in Turkey are taken from the report “Environmental Map” published by the Ministry of Environment and Forestry.

Any comment: -

B.6.3. Ex-ante calculation of emission reductions:

>>

Estimation of emission reductions prior to validation

According to “Consolidated baseline methodology for grid connected electricity generation from renewable sources” version 12.1.0, project participants should prepare an estimate of likely emission reductions for the proposed crediting period. This estimate is based on the same methodology as described under section B.6.1. Calculating the operating margin emission factor:

The simple operating margin CO2 emission factor is calculated as per equation (4).



For the calculation of the Simple OM, the amount of fuel consumption (FCi, y) is taken from website of TEIAS, which is the official source of related data. The fuel consumption values for relevant years are as follows: Table10 Fuel consumption of generation sources connected to the grid (2007-2009)

FCi, y

Units 2007 2008 2009 Total

Natural Gas 1000m3 20,457,793 21,607,635 20,978,040 63,043,468 Lignite tonnes 61,223,821 66,374,120 63,620,518 191,218,459 Coal tonnes 6,029,143 6,270,008 6,621,177 18,920,328 Fuel Oil tonnes 2,312,360 2,315,183 1,783,366 6,410,909 Turkish specific net calorific values (NCVi, y) values for fossil fuel types have been calculated, however, data from the IPCC Guidelines for National Greenhouse Gas Inventory have been used as the source of data for the emission factor of the fossil fuel types (EFCO2,i,y). The NCV and emission factors are as follows: Table11 NCV and emission factor of fossil fuel type NCVi (GJ/tonnes) EFCO2, i

(tonnes/GJ) 2007 2008 2009

Natural Gas 36.765 36.634 37.177 0,054 Lignite 6.861 6.827 6.427 0,091 Coal 22.303 22.244 22.215 0,095 Fuel Oil 39.960 39.874 40.091 0,073 The electricity delivered to the grid by all power sources serving the system, not including low-cost/must-run power plants/units (EGgross,y) is obtained from TEIAS (Turkish Electricity Transmission Company). The following table shows the gross electricity production for 2007-2009 produced by fossil fuel power sources. Table 12 Gross electricity generation by fossil fuel power sources 2007-2009

EGgross,y (MWh)

2007 2008 2009 Total

Natural Gas 95,024,800 98,685,300 96,094,700 289,804,800 Lignite 38,294,700 41,858,100 39,089,500 119,242,300 Coal 15,136,200 15,857,500 16,595,600 47,589,300 Fuel Oil 6,526,800 7,518,500 4,803,500 18,848,800 The gross electricity production includes the electricity consumption of the power plants. To be able to calculate the net electricity fed into the grid by specific fuel sources, an average correction factor had to be calculated from the overall gross/net electricity generation data. This relation is derived in in the following table.



Table 13 Relation between net and gross electricity generation 2007-2009 2007 2008 2009

Gross generation [MWh] 191,558,000 198,418,000 194,812,900 Net generation [MWh] 183,339,000 189,761,000 186,619,300 Relation 95.7% 95.6% 95.8% Average correction factor 95.7% The net electricity delivered to the grid by the fossil fuel plants (EGnet,y) is calculated in Table 14. The calculation of EFgrid,OM,y requires the inclusion of electricity imports with an emission factor of 0 tCO2/GWh. By including the imports in the electricity production this requirement is fulfilled.

Table 14 Net electricity generation by fossil fuel power plants and electricity imports 2007-2009 2007 2008 2009 Total

Net electricity production EGnet,y (MWh)

Natural Gas 90,951,136 94,454,712 91,975,170 277,381,017 Lignite 36,653,026 40,063,665 37,413,753 114,130,444 Coal 14,487,319 15,177,697 15,884,155 45,549,171 Fuel Oil 6,246,999 7,196,186 4,597,576 18,040,762

Electricity imports 864,300 789,400 812,000 2,465,700 Electricity supplied to grid EGy 149,202,780 157,681,659 150,682,654 457,567,094

Based on the above values, the simple operating margin CO2 grid emission factor (EFgrid,OMsimple,y) calculated through Equation 4 is 0.657 tCO2/MWh. Calculating the build margin emission factor The average CO2 emission factor of fuel types (EFCO2,m) and the average net energy conversion efficiency of the power plants (ηm,y) used for the calculation of emission factor of the power units (EFEL,m,y) through equation 6 are presented in the below table. Table 15 Emission factor of the power units Average emission factor

EFCO2,m,i,y

(tCO2/GJ)

Average conversion

efficiency ηm,y

Emission factor of the

power unit EFEL,m,y

(tCO2/MWh) Natural Gas 0,054 45.97% 0.425 Lignite 0,091 32.68% 1.001 Coal 0,095 33.57% 1.014 Fuel Oil 0,073 33.19% 0.788 Hydro n.a. n.a. 0 Wind n.a. n.a. 0 The data on the electricity generated and delivered to the grid by power units (EGm,y) are presented in the below table.



Table 16 Electricity generated by the power units included in the build margin calculation

EGm,y (MWh)

2005 2006 2007 2008 2009 Total

Natural Gas 415,000 3,102,795 3,343,903 765,780 13,602,509 21,229,986 Lignite 0 7,020,000 3,084 0 3,000 7,026,084 Coal 0 0 0 0 1,923,333 1,923,333 Fuel Oil 52,000 0 722,473 16,362 4,331,777 5,122,612 Hydro 0 212,339 717,432 128,145 1,402,961 2,460,877 Other renewable

0 69,448 0 0 1,189,986 1,259,434

Total 467,000 10,404,583 4,786,892 910,286 22,453,566 39,022,327 The build margin emission factor EFgrid,BM,y calculated through equation 5 is 0.565 tCO2/MWh. Calculating the combined margin emission factor

The combined margin emission factor EFgrid,CM,y calculated through equation 7 is 0.634 tCO2/MWh.

Project emissions

In accordance with the methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0), no project emissions need to be considered. PEy = 0 Leakage

In line with the requirements of ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0), no leakage emissions are considered

LEy=0 Calculating the baseline emissions

The baseline emissions are calculated based on the quantity of net electricity generation supplied to the grid in year y by the project plant/unit that has been added under the project activity. The following simplified formula has been applied based on equation (2) and equation (3).

CMgridyADDPJy EFEGBE ,,_ ⋅= (8)

Where: BEy Baseline emissions reductions in year y (tCO2/year) EGPJ_ADD,y Quantity of net electricity generation supplied to the grid in year y by the project

plant/unit that has been added under the project activity (MWh/yr)



EFgrid,CM Combined margin emission factor for grid connected power generation (tCO2/MWh)

The proposed project activity is estimated to generate 54,404 MWh/year of electricity, which corresponds to 34,477 tCO2/year baseline emissions calculated through equation (8). Calculating the emission reductions

As per equation (1), the annual emission reduction of the Project is estimated as 34,477 tCO2/year.

B.6.4 Summary of the ex-ante estimation of emission reductions:

>>

Table 17 Ex-ante estimation of emission reductions, summary table

Years

Estimation of

project activity

emissions

(tCO2e)

Estimation

of baseline

emissions

(tCO2e)

Estimation of

leakage

emissions

(tCO2e)

Estimation of

overall emission

reductions(tCO2e)

2012 0 14,365 0 14,365 2013 0 34,477 0 34,477 2014 0 34,477 0 34,477

2015 0 34,477 0 34,477

2016 0 34,477 0 34,477

2017 0 34,477 0 34,477

2018 0 34,477 0 34,477

2019 0 20,111 0 20,111 Number of

crediting years 7

Annual average

over the

crediting period

(tCO2e/y)

34,477

B.7. Application of the monitoring methodology and description of the monitoring plan:

B.7.1 Data and parameters monitored:

Data / Parameter: ID.9/EGPJ_ADD,y

Data unit: MWh Description: Quantity of net electricity generation supplied to the grid in year y by the project

plant/unit that has been added under the project activity Source of data to be Project activity site



used: Value of data applied for the purpose of calculating expected emission reductions in section B.5

54,404 MWh

Description of measurement methods and procedures to be applied:

The monitoring will be done by a private electricity meter, which will monitor the net electricity generation supplied to the grid by the project plant/unit that has been added under the project activity. The electricity will be measured continuously and recorded at least monthly.

QA/QC procedures to be applied:

Maintenance and calibration of equipment will be carried out according to the instructions of the manufacturer.

Any comment: This is applicable as the proposed project activity involves energy generation from wind sources and option 2 in the baseline methodology is applied.

B.7.2. Description of the monitoring plan:

>> All monitoring procedures and requirements of the proposed project activity is in accordance with the methodology ACM0002 “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (version 12.1.0).

Metering: The quantity of net electricity generation supplied to the grid by the units that has been added under the project activity will be monitored continuously by a meter, which will be owned, installed and maintained by the Project Participant. The measurements will be made at the project site. Data obtained from measurements will be used in calculations of emission reductions. The losses before this point will be on the account of the project owner.

Meter readings: Once a month, the project participant will perform data readings. The monthly results will be recorded by the project participant both manually and electronically. Data storage: Data will be stored electronically, during the crediting period and at least two years after the last issuance of credits for the wind farm project activity in the concerning crediting period. The Project Participant will be responsible for storage of data received from the measuring devices. Quality assurance and quality control: All metering devices will be calibrated by the project participant according to the specifications of the manufacturer. The specification of the meters will be in compliance with the requirements of the host country. Monitoring frequency: A high level of accuracy of the measurements will be achieved due to the use of high-precision equipment and due to strict compliance with the recommendations for calibration frequency of the equipment provider. Corrective actions and emergency preparedness: The Project Participant will regularly check the monitoring system on errors. In the case of errors, corrective actions will be undertaken by the Project Participant, or if required, by the supplier of the monitoring equipment.



B.8. Date of completion of the application of the baseline study and monitoring methodology

and the name of the responsible person(s)/entity(ies):

>> Date of completing the final draft of this baseline section:

13/10/2011 Name of person/entity determining the baseline:

The baseline has been prepared by OakDanışmanlık Company name: OakDanışmanlık Visiting Address: Acıbadem Mah. Şemibey Sok. Belkıs Apt. N:3 D:6 Kadıköy / Istanbul, TURKEY Contact Person: Ömer Akyürek Telephone number: +90 216 3471671 E-mail: [email protected]

SECTION C. Duration of the project activity / crediting period

C.1. Duration of the project activity:

C.1.1. Starting date of the project activity:

>> 01.11.2011 (Expected)

C.1.2. Expected operational lifetime of the project activity:

>> 49 years

C.2. Choice of the crediting period and related information:

C.2.1. Renewable crediting period:

C.2.1.1. Starting date of the first crediting period:

>> 01.08.2012

C.2.1.2. Length of the first crediting period:

>> 7 years, renewable

C.2.2. Fixed crediting period:

C.2.2.1. Starting date:

>>



C.2.2.2. Length:

>>

SECTION D. Environmental impacts

>>

D.1. Documentation on the analysis of the environmental impacts, including transboundary

impacts: >> In line with the requirements of “Regulation on Environmental Impact Assessment”, the proposed project has been exempted from performing an Environmental Impact Assessment.42

D.2. If environmental impacts are considered significant by the project participants or the host

Party, please provide conclusions and all references to support documentation of an environmental

impact assessment undertaken in accordance with the procedures as required by the host Party:

>> n.a.

SECTION E. Stakeholders’ comments

>>

E.1. Brief description how comments by local stakeholders have been invited and compiled: >> As required by the Gold Standard a Local Stakeholders Consultation and a Feedback Round has to be undertaken by the project participant in order to encourage the stakeholders to express their opinion and incorporate it in the project. In this way, the project developer, together with the public, ensures a project going along the main principles of sustainability. For more details on both the Local Stakeholder Consultation (LSC) and the Stakeholder Feedback Round see the LSC report and the GS Passport43. Local Stakeholder Consultation (LSC)

The proposed project activity is exempted from conducting an Environmental Impact Assesment (EIA) according to Turkish Law and Regulations however the project participant has organized a Local Stakeholders Meeting on 06.06.2011 in accordance with the requirements of the Gold Standard Foundation v2.1. The LSC meeting was held at Dualar Village near the project site. In general the participation to the meeting was good with more than 41 people and achieved a female participation of 50%. Before the meeting the following documents have been provided to the stakeholders: + Non-technical description of the project activity (also submitted along with the invitations); + Meeting evaluation forms; + Questionnaire regarding the sustainable development indicators and monitoring of the indicators along with the explanation of the indicators (also submitted along with the invitations).

42 Exemption letter has been provided to the validating DOE

43 Gold Standard v.12 rules and requirements are applicable to the proposed project activity.



The meeting has started with introduction of the representatives of the Project Participant Mrs. Çağla Balcı Eriş and Mrs. Sıla Kılıç, explaining the aim of the meeting. Also a brief explanation was made with regards to the documents provided before the start of the meeting. The introduction followed by the explanation of the project activity, followed by a question and answer session. Since the proposed project activity is the extension of an existing power plant, the locals were quite informed about the activities. There were no concerns on the impact of the proposed project activity to sustainable development and environmental.

Stakeholder Feedback Round (SFR)

This section will be updated after the completion of the feedback round

E.2. Summary of the comments received: >> The details of the Stakeholders Consultation Process could be found under the GS LSC Report and the GS Passport.

E.3. Report on how due account was taken of any comments received: >> The details of the Stakeholders Consultation Process could be found under the GS LSC Report and the GS Passport.



Annex 1

CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY

Organization: Polat Enerji Sanayi Ticaret A.Ş. Street/P.O.Box: Büyükdere Cad. Building: Polat Holding City: Mecidiyeköy / Đstanbul State/Region: Postcode/ZIP: 34387 Country: Turkey Telephone: +90 212 2136635 FAX: +90 212 2136639 E-Mail: URL: www.polatenerji.com Represented by: Sıla Kılıç Title: Salutation: Mrs. Last name: Kılıç Middle name: First name: Sıla Department: Mobile: Direct FAX: Direct tel: Personal e-mail: [email protected]

Organization: Demirer Enerji Üretim Sanayi ve Ticaret A.Ş. Street/P.O.Box: Mashar Osman Sokak Building: 9/1 City: Feneryolu / Kadıköy, Đstanbul State/Region: Postcode/ZIP: Country: Turkey Telephone: +90 216 3360148 FAX: +90 216 3300654 E-Mail: [email protected] URL: Represented by: Çağl Balcı Eriş Title: Salutation: Mrs. Last name: Eriş Middle name: Balcı First name: Çağla Department:



Mobile: Direct FAX: Direct tel: Personal e-mail: [email protected] / [email protected]



Annex 2

INFORMATION REGARDING PUBLIC FUNDING

No public funding from the Annex I countries is provided to the proposed project.



Annex 3

BASELINE INFORMATION

SETsample

2009

Plant Name Fuel Type

Added

Installed

Capacity Generation

MW MWh

Ak Gıda San. Ve Tic. A.Ş. (Pamukova) Natural Gas 7.50 61,000 Aksa Akrilik Kimya San. A.Ş. (Yalova) Natural Gas 70.00 539,000 Aksa Enerji (Antalya) Natural Gas 16.20 124,740 Aksa Enerji (Antalya) Natural Gas 300.00 2,310,000 Aksa Enerji (Antalya) Natural Gas 300.00 2,310,000 Aksa Enerji (Manisa) Natural Gas 10.50 83,144 Antalya Enerji Natural Gas 41.80 302,096 Arenko Elektrik Üretim A.Ş. (Denizli) Natural Gas 12.00 84,000 Bil Enerji (DG+M)(Balgat) Natural Gas 36.60 255,000 Cam İş Elektrik Natural Gas 126.10 1,008,000 Çelikler Taah. İnş. (Rixox Grand) Natural Gas 2.00 16,000 Dalsan Alçı San. Ve Tic A.Ş. Natural Gas 1.20 9,000 Delta Enerji Üretim ve Tic. A.Ş. Natural Gas 47.00 365,817 Delta Enerji Üretim ve Tic. A.Ş. Natural Gas 13.00 101,183 Desa Enerji Elektrik Üretim A.Ş. Natural Gas 9.80 70,000 E. Şehir. End. Enerji (DG+M)(Eskişehir-2) Natural Gas 59.00 452,000 Ege Birleşik Enerji (LPG+DG+M)(Aliağa) Natural Gas 12.80 107,000 Entek Köseköy (İztek) Natural Gas 0.80 6,366 Entek Köseköy (İztek) Natural Gas 36.30 288,876 Falez Elektrik Üretim A.Ş. Natural Gas 11.70 88,000 Global Enerji (Pelitlik) Natural Gas 8.60 65,665 Gül Enerji Elkt. Üret. Sn. Ve Tic. A.Ş. Natural Gas 24.30 170,000 Habaş Aliağa Natural Gas 224.50 1,796,000 Hayat Kağıt Natural Gas 7.50 56,000 Kasar Dual Tekstil San. A.Ş. (Çorlu) Natural Gas 5.70 38,000 Ken Kipaş Elektrik Üretim (Karen) Natural Gas 41.80 180,000 Ken Kipaş Elkt. Ür. (Karen) (K.Maraş) Natural Gas 17.50 75,359 Maksi Enerji EeLEKTRİK Üretim A.Ş. Natural Gas 7.70 55,000 Marmara Pamuklu Mens. Sn. Tic. A.Ş. Natural Gas 34.90 271,533 Mauri Maya San A.Ş. Natural Gas 0.30 2,478 Mauri Maya San A.Ş. Natural Gas 2.00 16,522 Modern Enerji (B. Karıştıran) Natural Gas 96.80 MOSB Enerji Elektrik Üretim Ltd. Şti. Natural Gas 84.80 595,702 Nuh Çimento San. Tic. A.Ş. Natural Gas 47.00 329,000 Rasa Enerji (VAN) Natural Gas 78.60 500,000



Selkasan Kağıt Paketleme Natural Gas 9.90 73,000 Sönmez Elektrik (Uşak) Natural Gas 8.70 67,057 Şahinler Enerji (Çorlu/Tekirdağ) Natural Gas 26.00 185,000 TAV İstanbul Terminal İşletme A.Ş. Natural Gas 3.30 27,612 TAV İstanbul Terminal İşletme A.Ş. Natural Gas 6.50 54,388 Tesko Kipa Kitle Paz. Tic. Ve Gıda A.Ş. Natural Gas 2.30 18,000 Yurtbay Elektrik Üretim A.Ş.(DG+M) Natural Gas 6.90 50,000 Zorlu Enerji (B. Karıştıran) Natural Gas 49.50 394,970 Natural Gas 2009 Total 1,909.40 13,602,509

Erdemir (Ereğli-Zonguldak) Fuel Oil 39.20 240,000 Habaş Bilecik Paşalar Fuel Oil 18.00 144,000 Habaş İzmir Habaş Fuel Oil 36.00 288,000 Petkim (Aliağa) Fuel Oil 222.00 1,554,000 Petkim (Aliağa) Fuel Oil 52.00 364,000 Silopi Elektrik Üretim A.Ş. Fuel Oil 44.80 315,000 Süper Film (G. Antep) Fuel Oil 25.30 203,000 Tire Kutsan (Tire) Fuel Oil 8.00 37,000 Tüpraş Rafineri (Aliağa/İzmir) Fuel Oil 24.70 171,777 Tüpraş O.A. Rafineri (Kırıkkale) Fuel Oil 10.00 70,000 Silopi Elektrik Üretim A.Ş. Fuel Oil 135 945000 Fuel Oil 2009 Total 615.00 4,331,777

Alkim Alkali Kimya Lignite 0.40 3,000 Lignite 2009 Total 0.40 3,000

İçdaş Çelik Coal 135.00 961,667 İçdaş Çelik Coal 135.00 961,667 Coal 2009 Total 270.00 1,923,333

Akçay Hes Elektrik Üretim (Akçay HES) Hydro 28.80 45,000 Akua Enerji (Kayalık Reg ve HES) Hydro 5.80 20,000 Anadolu Elektrik (Çakırlar HES) Hydro 16.20 28,000 Bağışlı REG ve HES (Ceykar Elekt.) Hydro 9.90 15,720 Bağışlı REG ve HES (Ceykar Elekt.) Hydro 19.70 31,280 Bereket Enerji (Koyul Hisar) Hydro 42.00 155,000 Beyobası En. Ür. A.Ş. (Sırma HES) Hydro 5.90 11,000 Cindere HES (Denizli) Hydro 19.10 30,000 Değirmenüstü En (Kahramanmaraş) Hydro 12.90 17,378 Denizli Elektrik (EGE I HES) Hydro 0.90 2,000 Elestaş Elektrik (Yaylabel HES) Hydro 5.10 10,000 Elestaş Elektrik (Yazı HES) Hydro 1.10 3,000



Erva Enerji (Kabaca Reg ve HES) Hydro 4.20 7,412 Erva Enerji (Kabaca Reg ve HES) Hydro 4.20 7,412 Filyos Enerji (Yalnızca Reg ve HES) Hydro 14.40 33,000 Kalen Enerji (Kalen I II HES) Hydro 15.70 23,575 Karel Enerji (Pamukova) Hydro 9.30 40,000 Kayen Alfa Enerji (Kaletepe HES) Hydro 10.20 17,000 Kısık Hydro 9.60 20,000 Lamas II IV HES (TGT Enerji Üretim) Hydro 35.70 71,000 Obruk HES Hydro 212.40 337,000 Öztay Enerji (Günayşe Reg ve HES) Hydro 8.30 14,000 Özyakut Elek. Ür. A.Ş. (Güneşli HES) Hydro 0.60 1,333 Özyakut Elek. Ür. A.Ş. (Güneşli HES) Hydro 1.20 2,667 Reşadiye 3 HES (Turkon MNG Elekt.) Hydro 22.30 88,000 Sarıtepe HES (Genel Dinamik Sis. El) Hydro 2.50 4,592 Sarıtepe HES (Genel Dinamik Sis. El) Hydro 2.50 4,592 Şirikçioğlu El. (Kozak Bendi ve HES) Hydro 4.40 7,000 Taşova Yenidereköy HES (Hameka A.Ş.) Hydro 2.00 6,000 Tektuğ (Erkenek) Hydro 6.00 14,400 Tektuğ (Erkenek) Hydro 6.50 15,600 Tocak I HES (Yurt Enerji Üretim Sn.) Hydro 4.80 6,000 Tüm Enerji (Pınar Reg ve HES) Hydro 30.10 65,000 Uzunçayır HES (Tunceli) Hydro 27.30 49,000 Yapısan (Karıca Reg ve Darıca HES) Hydro 48.50 77,000 Yapısan (Karıca Reg ve Darıca HES) Hydro 48.50 77,000 Yeşilbaş Enerji (Yeşilbaş HES) Hydro 14.00 26,000 ypm Gölova HES (Suşehri / Sivas) Hydro 1.10 2,000 YPM Sevindik HES (Suşehri / Sivas) Hydro 5.70 18,000 Hydro 2009 Total 719.40 1,402,961

Gürmat Elektrik (Gürmat Jeotermal) Geothermal 47.40 313,000 Alize Enerji (Sarıkaya RES) (Şarköy) Wind 28.80 96,000 Baki Elektrik (Şamlı Rüzgar) Wind 36.00 176,000 Baki Elektrik (Şamlı Rüzgar) Wind 33.00 161,333 Belen Elektrik Belen Rüzgar-Hatay Wind 15.00 47,500 Belen Elektrik Belen Rüzgar-Hatay Wind 15.00 47,500 Borasko Enerji (Bandırma RES) Wind 21.00 83,533 Borasko Enerji (Bandırma RES) Wind 24.00 95,467 Cargill Tarım ve Gıda San. Tic. A.Ş. Biogas 0.10 700 Ortadoğu Enerji (Kömürcüoda) Waste 5.80 45,000 Ortadoğu Enerji (Oda Yeri) Waste 4.20 33,071 Ortadoğu Enerji (Oda Yeri) Waste 5.70 44,882 Ütopya Elektrik (Düzova RES) Wind 15.00 46,000 Renewable 2009 Total 253.80 1,189,986.09

2009 Total 3,768.00 22,453,566



2008

Plant Name Fuel Type

Added

Installed

Capacity Generation

MW MWh

MB Şeker Nişasta San A.Ş Natural Gas 8.80 0 Aksa Enerji (Antalya) Natural Gas 183.80 133,736 Aksa Enerji (Manisa) Natural Gas 52.38 79,183 Antalya Enerji (İlave) Natural Gas 17.46 85,341 Ataç İnşaat San. A.S.B. (Antalya) Natural Gas 5.40 10 Bahçivan Gıda (Lüleburgaz) Natural Gas 1.17 0 Can Enerji (Çorlu Tekirdağ) (İlave) Natural Gas 52.38 255,164 Four Seasons Otel (Atik Paşa Tur A.Ş.) Natural Gas 1.17 0 Fritolay Gıda San. Ve Tic. A.Ş. (İlave) Natural Gas 0.01 0 Melike Tekstil (Gaziantep) Natural Gas 1.58 0 Misis Apre Tekstil Boya En. San. Natural Gas 2.00 5,324 Modern Enerji (Lüleburgaz) Natural Gas 13.40 70,453 Polat Turz (Polat Reniassance Ist. Ot.) Natural Gas 1.60 490 Yıldız Sunta (Uzunçıftlik Köseköy) Natural Gas 22.63 136,018 Sönmez Elektrik Natural Gas 8.73 61 Natural Gas 2008 Total 372.50 765,780

Karkey (Silopi 5) (154kV) (İlave) Fuel Oil 14.78 16,362 Fuel Oil 2008 Total 14.78 16,362

Akköy Enerji (Akköy I HES) Hydro 101.94 21,608 Alp Elektrik (Tınaztepe) Antalya Hydro 7.69 9,245 Cansu Elektrik (Murgul/Artvin) Hydro 9.18 12,518 Çaldere Elk. (Çaldere HES) Dalaman Muğla Hydro 8.74 11,153 Daren HES Elkt. (Seyrantepe Barajı ve HES) Hydro 49.70 14,370 Değirmenüstü En. (Kahramanmaraş) Hydro 25.70 0 Gözede HES (Temsa Elektrik) Bursa Hydro 2.40 6,107 H.G.M. Enerji (Keklicek HES) (Yeşilyurt) Hydro 8.67 120 Hamzalı HES (Turkon MNG Elektrik) Hydro 16.70 2,936 Hidro KNT. (Yukarı Manahoz Reg. Ve HES) Hydro 22.40 13,772 İç-En Elk. (Çalkışla Regülatörü ve HES) Hydro 7.66 3,364 Kalen Enerjş (Kalen II Regülat. Ve HES) Hydro 15.65 10,281 Maraş Enerji (Fırnıs Regülatörü ve Hes) Hydro 7.22 0 Sarmaşık I HES (Fetaş Fethiye Enerji) Hydro 21.04 1,472 Sarmaşık II HES (Fetaş Fethiye Enerji) Hydro 21.58 1,221 Torul Hydro 105.60 18,551 Yeşil Enerji Elektrik (Tayfun HES) Hydro 0.82 0 Zorlu Enerji (Mercan) Hydro 1.28 1,427 Hydro 2008 Total 433.97 128,145



2008 Total 821,25 910.286

2007

HABAŞ (Aliağa-ilave) Natural Gas 9.10 72,800 Moder Enerji Natural Gas 5.20 38,717 Arenko Natural Gas 0.70 5,567 Altınmarka Gıda Natural Gas 0.10 806 Tekboy Enerji Natural Gas 0.10 727 Velsan Akrilik Natural Gas 0.10 263 Acıbadem Sağlık Kadıköy Natural Gas 0.50 6,250 Acıbadem Sağlık Kozyatağı Natural Gas 0.60 5,000 Acıbadem Sağlık Bursa Natural Gas 1.30 11,000 Akateks Tekstil Sanayi Natural Gas 1.80 14,000 Flokser Tekstil Poliser Natural Gas 2.10 17,000 Flokser Tekstil Süetser Natural Gas 2.10 17,000 Fritolay Gıda Natural Gas 0.50 4,000 Kıvanç Tekstil Natural Gas 3.90 33,000 Kil San Natural Gas 3.20 25,000 Superboy Boya San Natural Gas 1.00 8,000 Swiss Hotel Natural Gas 1.60 11,000 TAV Esenboğa Natural Gas 3.90 33,000 Nuh Enerji 2 Natural Gas 73.00 514,000 Boğazlıyan Şeker Liquid + Natural Gas 16.40 43,075 Kartonsan Liquid + Natural Gas 5.00 40,000 Eskişehşir End. Enerji Liquid + Natural Gas 3.50 26,814 Eskişehir Şeker Liquid + Natural Gas 2.90 7,617 İgsaş Liquid + Natural Gas 2.20 15,200 Bil Enerji Natural Gas 0.10 697 BİS Enerji Üretim Natural Gas 43.00 354,802 Aliağa Çakmaktepe Enerji Natural Gas 34.80 278,000 Bis Enerji Üretim Natural Gas 28.30 233,510 BİS Enerji Üretim Natural Gas 48.00 396,059 Bosen Enerji Elektrik Natural Gas 142.80 1,071,000 Sayenerji Elektrik Üretim A.Ş. Natural Gas 5.90 47,000 T Enerji Üretim A.Ş. Natural Gas 1.60 13,000 Natural Gas 2007 Total 445.30 3,343,903

Akteks Fuel Oil 0.80 2,504 Süper filmcilik Fuel Oil 0.10 802 Zorlu Eenerji Kayseri Fuel Oil 7.20 54,964 Siirt Fuel Oil 25.60 190,000 Mardin Kızıltepe Fuel Oil 34.10 106,734 Karen Fuel Oil 24.30 180,000 İdil 2 Fuel Oil 24.40 180,000 Desa Naphta 0.70 4,623



Dentaş Naphta 0.30 2,280 Ataer Enerji Naphta 0.10 566 Fuel Oil 2007 Total 117.60 722,473

Uşak Şeker Lignite 1.70 3,084 Lignite 2007 Total 1.70 3,084

Borçka HES Hydro 300.60 600,000 Tektuğ Hydro 5.00 20,000 YPM Ener Yat A.S. Altıntepe Hidro Hydro 4.00 10,000 YPM Ener Yat A.S. Beypınar Hidro Hydro 3.60 9,000 YPM Ener Yat A.S. Konak Hidro Hydro 4.00 1,000 Kurteks Tekstil Hydro 2.40 19,000 Iskur Tekstil Hydro 4.60 4,000 Özgür Elek. A.Ş. Hydro 6.30 27,216 Özgür Elek. A.Ş. (ilave) Hydro 6.30 27,216 Hydro 2007 Total 336.80 717,432

2007 Total 901.40 4.786.892

2006

Ekoten Tekstil GR-I Natural Gas 1.93 14,015 Erak Giyim GR-I Natural Gas 1.37 9,750 Alarko Altek GR-III Natural Gas 21.89 158,302 Aydın Örme GR-I Natural Gas 7.52 60,160 Nuh Enerji 2 GR-II Natural Gas 26.08 180,059 Marmara Elektrik (Çorlu) GR-I Natural Gas 8.73 62,499 Entek GR-IV Natural Gas 47.62 378,198 Else Tekstil (Çorlu) GR-I II Natural Gas 3.16 24,688 Sönmez Elektrik (Çorlu) GR-I II Natural Gas 17.46 125,712 Denizli Çimento (Düzeltme) Natural Gas 0.45 3,179 Kastamonu Entegre (Balıkesir) GR I Natural Gas 7.52 54,144 Boz Enerji GR I Natural Gas 8.73 70,241 Amylum Nişasta (Adana) Natural Gas 14.25 33,881 Şık Makas (Çorlu) GR I Natural Gas 1.58 12,838 Antalya Enerji GR I II III IV Natural Gas 34.92 245,140 Hayat TEM ve Sağlık GR I II Natural Gas 15.04 108,288 Eroğlu Giyim (Çorlu) GR I Natural Gas 1.17 8,738 Cam İş Elktrik (Mersin) GR I Natural Gas 126.10 1,008,000 Yıldız Ent. Ağaç (Kocaeli) GR I Natural Gas 6.18 39,897 Çerkezköy Enerji GR I Natural Gas 49.16 389,715 Çırağan Sarayı GR I Natural Gas 1.32 11,203 Akmaya (Lüleburgaz) GR I Natural Gas 6.91 50,072 Burgaz (Lüleburgaz) GR I Natural Gas 6.91 54,078 Natural Gas 2006 Total 416 3,102,795



Elbistan B GR III Lignite 360.00 2,340,000 Elbistan B GR II Lignite 360.00 2,340,000 Elbistan B GR IV Lignite 360.00 2,340,000 Lignite 2006 Total 1,080.00 7,020,000

Menderes Elektrik GR-I Geothermal 7.95 55,657 Adana Atıksu Arıtma Tesisi Biogaz 0.80 6,023 Ekolojik Enerji (Kemerburgaz) GR I LFG 0.98 5,880 Ertürk Elektrik Tepe RES GR I Wind 0.85 1,889 Renewable 2006 Total 11 69,448

Seyhan I II Hydro 0.30 1,171 Şanlıurfa GR I II Hydro 51.80 0 Bereket Enerji Gökyar HES 3 Grup Hydro 11.62 28,048 Molu En. Zamantı Bahçelik GR I II Hydro 4.22 10,501 Su Enerji (Balıkesir) GR I II Hydro 4.60 4,203 Bereket Enerji (Mentaş Reg) GR I II Hydro 26.60 93,333 Ekin (Başaran HES) (Nazilli) Hydro 0.60 2,900 Ere (Sugözü rg. Kızıldüz HES) GR I II Hydro 15.43 7,916 Ere (Aksu Reg. Ve Şahmallar HES) GR I II Hydro 14.00 6,600 Tektuğ (Kalealtı) GR I II Hydro 15.00 11,000 Bereket EN. (Mentaş Reg) GR III Hydro 13.30 46,667 Hydro 2006 Total 157 212,339

2006 Total 1,664.06 10,404,583

2005

AKÇA ENERJİ GR-III Natural Gas 8.73 65,000

BOSEN GR-III Natural Gas 50.00 350,000 Natural Gas 2005 Total 58.73 415,000

KARKEY(SİLOPİ-4) GR-V Fuel Oil 6.75 52,000 Fuel Oil 2005 Total 6.75 52,000

2005 Total 65.48 467,000

Annex 4

MONITORING INFORMATION

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