PDD - Netinform

PROJECT DESIGN DOCUMENT FORM (CDM-SSC-PDD) - Version 03

CDM – Executive Board

CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN DOCUMENT FORM (CDM-SSC-PDD) Version 03 - in effect as of: 22 December 2006 CONTENTS A.

General description of the small scale 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 proposed small scale project activity Annex 2: Information regarding public funding Annex 3: Baseline information Annex 4: Monitoring Information Annex 5: Electricity Generation License Annex 6:EIA Exemption Letter

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Revision history of this document

Version Number 01 02

Date

Description and reason of revision

21 January 2003 8 July 2005

Initial adoption  

03

22 December 2006



The Board agreed to revise the CDM SSC PDD to reflect guidance and clarifications provided by the Board since version 01 of this document. As a consequence, the guidelines for completing CDM SSC PDD have been revised accordingly to version 2. The latest version can be found at . The Board agreed to revise the CDM project design document for small-scale activities (CDM-SSC-PDD), taking into account CDM-PDD and CDM-NM.

2



SECTION A. General description of small-scale project activity A.1

Title of the small-scale project activity:

Title: Saray HEPP Version: 01 Date: 03.03.2012

A.2.

Description of the small-scale project activity:

Saray HEPP Project (hereinafter referred to as ‘the proposed project’) is a run-of-river small hydropower plant, owned by MERTLER Enerji Uretim Pazarlama A.S. It is located on Iyidere stream of Eastern Black Sea Basin within the borders of Of county, Trabzon province by the border of Rize Province in order to appraise the tail water of Incirli HEPP project in Kalkandere county of Rize province in Turkey. Incirli HEPP is a run-of-river activity that belongs to Laskar Enerji Uretim Pazarlama A.S. Since the project is appraising the tailwater of Incirli HEPP via a water intake structure, there is no diversion weir or derivation tunnel in the project structure. In order to assure the minimum flow for the stream, the diversion weir of Incirli HEPP is designated to leave the minimum amount of water for both of the projects. The installed capacity of the project is 13.5 MW and the projected annual electricity production is 46.89 GWh/y1. According to methodology AMS I.D (Version 17), the physical, geographical site of the renewable generation source delineates the project boundary. In addition, according to AMS I.D. (Version 17), only CO2 emissions from electricity generation should be accounted for as the main source of emission. CO2 emissions from electricity generation in fossil fuel fired power plants are displaced due to the project activity and its technology. When developed with care to footprint size and location, run-of-river hydro projects can create sustainable green energy that minimizes impacts to the surrounding environment and nearby communities. Like all hydro-electric power, run-of-river hydro harnesses the natural energy of water and gravity – eliminating the need to burn coal or natural gas to generate the electricity needed by consumers and industry. Substantial flooding of the upper part of the river is not required for small runof-river projects as a large reservoir is not required. As a result, people living at or near the river don't need to be relocated and natural habitats and productive farmlands are not wiped out. In addition there is no project emission regarding to the surface area of a dam which produces GHG. A dam also acts as a barrier between the upstream and downstream movement of migratory river animals. Dams block their migration upstream to spawning areas, threatening to decrease reproduction numbers and reduce the species population. The run-of-river technology of the proposed project eliminates all of these undeserved consequences. The baseline scenario is the same as the existing scenario prior to the implementation of the project activity. The project won’t produce any greenhouse gas (GHG) during the operation. The electricity generated by the project can displace part of the power from the fossil fuel-fired power plants of Turkey and the expected annual GHG emission reductions are 33,010.5 tCO2e. The net electricity generation of the facility is multiplied by 0.704 tCO2e/MWh emission factor for the conservative approach2. Contribution to sustainable development: 1

2

Annex 5: Energy Generation License Please refer to section B.4 for further and detailed information

3



Contribution and enhancing the sustainable development: The project activity will promote the local and national sustainable development in the following aspects: 

Reducing the GHG emission to mitigate the global warming trend by providing clean electric power.



Reduction of Turkish dependency on electricity imports3. FIGURE 1: Turkish Electricity Imports and Exports4



Promoting the local economic development of the region, creating job opportunities during the construction period and operation period. It is projected that during the project’s construction period 60 people and throughout the operation period 20 people will be employed.

In order to receive the EIA exemption report, the mitigation measures and parameters that are regulated by the national law had been carefully studied and fulfilled in order to proof the no harm principle of the project activity. In the presentation note of the case, the environmental, sustainable, economical and technical aspects of the proposed project have been discussed. In the table below, the particular indicators which are considered in EIA exemption report can be found.

3

For electricity generation and imports in order to supply demand in Turkey, please refer to: http://www.teias.gov.tr/istatistik2009/23.xls) 4

http://www.tetas.gov.tr/Uploads/yıllar_ithalat-ihracat.JPG

4



TABLE 1: Analyzed components in the EIA report: Waste water amount and water quality calculations Dust dispersive operations and quantity calculations Noise derivations and level calculations Solid waste types and amount Waste oil and petrol Risk of accident assessment which may emanate from the use of technology and equipment, in respect to the National Worker’s Health and Safety Regulations. Adopted actions against potential and unexpected environmental impacts Terrain tenancy, quality and soil condition (Agricultural fields, forest region, water resources, water surface, etc.) Geological conditions of the region and relevant studies Exquisite districts* located in close proximity to the project area Impact on local flora and fauna

*Exquisite districts comprises of wetlands, shorelines, sylvan and mountainous regions, agricultural fields, national parks, special protected environmental areas, wildlife protection areas, highly populated areas, historical, cultural and archeological heritage zones, soil erosion areas, forestation areas and subterranean waters. As a result of this assessment, it has been approved that the project activity contains no harm, barrier or mutation for the regional components above. However in the region, tea and nut plantations are the mainstay for the local population. Tea plant’s principle root goes down to 2.5 meters under the ground. The project’s transmission tunnel goes underground at an average depth of 100 meters. The tunnel goes down at a maximum depth of 200 meters and minimum depth of 3.5 meters. Considering the 2.5 meters of the tea plant’s principle root, the project’s transmission tunnel measuring 3,640.00 meters has no effect on the plantations on the ground. The project does not include any kinds of reservoirs or water storage units ensuring the GHG emission of the project to be zero and do not hold any initiative on the flow amount of the water that will be released in the river bed on a predetermined schedule. The powerhouse rests on 3000 m2 field of brushwood that is no arable. The forebay rests on 5300 m2 tea plantation. The transmission tunnel, forebay and penstock rest on the freeholder’s private property. Expropriation of the lands will be held according to the national law and regulations. The project’s ground assets and their usage details are explained in the table below:

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Components

TABLE 2: Current Soil Type Purpose of Land Use

Land Use Quality

Powerhouse

Alluvial Soil

Tea Cultivated Land

Inadequate for agricultural use, adequate for plow farming

Pipe culvert and water intake structure

Red and Yellow Podzolic Soil

Tea, Nut, Dry Farming Cultivated Land

Inadequate for plowless farming

Tea Cultivated Land

Inadequate for agricultural use, adequate for plow farming

Penstock and Forebay

Alluvial Soil

According to the requirements of the Gold Standard, the project activity must be assessed against a matrix of sustainable development indicators. The contribution of the proposed project activity to sustainable development of the country is based on the local/global environmental sustainability, social sustainability & development and economic & technological development. The matrix is presented in Table 1. The environmental, sustainable, economical and technical aspects of the proposed project have been discussed with stakeholders affected by the project. TABLE 3: Score Comparison Table for Sustainable Development Matrixes for Gold Standard: Sustainable Indicator Air Quality Water Quality and Quantity Soil Condition Other Pollutants Biodiversity Quality of Employment Livelihood of the Poor Access to Clean and Affordable Energy Services Human and Institutional Capacity Quantitative Employment and Income Generation Balance of Payments and Investment

Project Developers’ Scoring 0 0 0 0 0 + 0

Stakeholders Scoring 0 0 0 + + +

0

0

0

0

0

0

0

0

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Technology Transfer and Technological Self-reliance.

+

0

Explanation of the indicators: Air Quality: Stakeholders scored this indicator 0 because the project generates energy without causing air pollution and do not have an impact on the air quality. Water Quality and Quantity: It has been clearly expressed that the proposed project has no negative impact on the water quality since no liquid or inert waste will flow into the river as a result of the project’s operation. The quantity of the water will have a slight change, but since the necessary official permits have been obtained and presented to the stakeholders, they are certain that this change will not affect their water need and access to it. Soil Condition: Since the project does not have any negative impact in the soil condition and a landscaping plan will be implemented after the construction, the stakeholders scored this indicator 0. They were satisfied that the soil that will be taken out in the excavation will be used for land development and they can use it for their farming activities. Other Pollutants: The stakeholders were uncomfortable about the blasts in the constructional phase of the project. The detonation activities and its noise have been considered as noise pollutant and the locals chose to score this indicator negative. Biodiversity: In the meeting the locals raised attention to the river life and how it will be affected from the project. Mentioning the fish passage and the gravel pass in the diversion weir of Incirli HEPP, it was assured that the project had adapted serious measures to sustain the natural habitat of the river bed. In addition the presentation of official limits for water usage of the proposed project and serious supervision that will be performed on by government officials were positive effects on the stakeholders that the biodiversity is an essential point that will be strictly supported by the project activity. Showing their satisfaction and relief, the stakeholders scored this indicator positive. Quality of Employment: The staff of plant operation will be trained by the manufacturer company allowing them to get familiar with the latest technological developments and gain expertise. In the constructional phase, it has been ensured that all the related regulations for workers safety and health will be adapted. Since the project activity will perform local employment at these ideal standards, the stakeholders had scored this indicator positive. Livelihood of the Poor: The stakeholders scored this indicator positive as the project will create new job opportunities in the area, but still it has been scored 0, as these new employments will not make a significant change in the well being of the people in macro scale.

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Access to Clean and Affordable Energy Services: It has been clearly explained to the stakeholders that due to the governmental structure of the electricity generation and distribution in national scope, nobody holds any privileges to access cheap electricity, even the project owner himself. Therefore this indicator has been scored 0. Human and Institutional Capacity: Because of the fact that the project owner will support the socio-economic life of the local people, they are optimistic and motivated about the project activity. However since the project will not have a particular impact on the human and institutional capacity of the area, this indicator has been scored 0. Quantitative Employment and Income Generation: It is for sure that the project will create periodic and full time job opportunities during its construction and operation but even though the quality of employment has been scored positively by the stakeholders, the project activity will not restore the income generation gaps and imbalance in the region. Therefore the indicator has been scored 0. Balance of Payments and Investment: Even though the project is encouraged as a private enterprise which will affiliate another renewable resource to the electricity generation profile of the country and contributes to the reduction of poverty by the employment opportunities and charity works in micro scale, this indicator has been scored as 0 due to its effect on the general sector profile in the country and international financing structure. Technology Transfer and Technological Self-reliance: The staff which will be responsible from the plant operation will be trained by the manufacturer company and this will increase the technological knowledge of the local technicians. However, since Turkey is in position of importing the mechanical equipment for hydropower technology and not been procured locally, this indicator has been scored as 0 by the stakeholders.

A.3.

Project participants: TABLE 4:

Name of Party involved(*) ((host) indicates a host Party)

The Republic of Turkey (host)

Private and/or public entity(ies) Project participants(*) (as applicable) MERTLER Enerji Uretim Pazarlama A.S. (project owner)

Kindly indicate if the Party involved wishes to be considered as project participant (Yes/No) NO

The Republic of Turkey Borga Karbon Danismanlik Ith. NO (host) Ihr. Ve Paz. Tic. Ltd. Sti. (*) In accordance with the CDM modalities and procedures, at the time of making the CDM-PDD public at the stage of validation, a Party involved may or may not have provided its approval. At the time of requesting registration, the approval by the Party(ies) involved is required.

8





MERTLER Enerji Uretim Pazarlama A.S. is the generation license owner of the project activity. According to the license and System Connection and Water Usage Agreement provided by the distribution company, the only project proponent is MERTLER Enerji Uretim Pazarlama A.S.



Borga Karbon Danismanlik Ith. Ihr. Ve Paz. Tic. Ltd. Sti. is the carbon consultant, PDD writer, baseline study and monitoring methodology developer for this project.

A.4.

Technical description of the small-scale project activity: A.4.1. Location of the small-scale project activity:

A.4.1.1.

Host Party(ies):

Republic of Turkey. A.4.1.2.

Region/State/Province etc.:

Eastern Black Sea Region. Trabzon and Rize Provinces. A.4.1.3.

City/Town/Community etc:

Of County. A.4.1.4. Details of physical location, including information allowing the unique identification of this small-scale project activity : Trabzon province is located on the north of Turkey on the coast of Black Sea, within the borders of Black Sea Region. The project area is located on 60 km distant to Trabzon city center, 12 km distant to Of county center, in Ikidere locality. The project component’s distance between the nearest residential area are explained in the table below5: TABLE 5: Component

Distance to Residential Area

Powerhouse Pipe culvert and water intake structure Forebay Penstock

95 meters

Position according to the Residential Area South

210 meters

North, on the right shore

95 meters 110 meters

Northeast West

5

The project component’s distance between the nearest residential area are measured under the guidance and directives of the representative from Provincial Department of Environment and Forestry via Google Earth

9



The project components and their coordinates are listed in the table below: TABLE 6: COMPONENT Powerhouse Transmission Tunnel Forebay Culvert Penstock

LATITUDE (N) : LONGITUDE (E) 40.96583952 : 40.35394198 40.95953334 : 40.39590042 40.96437905 : 40.35467823 40.95948689 : 40.39894414 40.96429302 : 40.35439656

Incirli HEPP located on the right shore of Iyidere Stream provides the water for the project activity to derive its energy. The tailwater of Incirli HEPP is transferred to the left shore of Iyidere Stream via culvert pipe. The water follows into the surge tank before the water inlet of the transmission tunnel measuring 3,540 meters. It reaches to the turbines located in the powerhouse via forebay and penstock. By a tailwater canal, the water will be released to Iyidere Stream. The project area, containing the project components that are mentioned above, can be described as a little hilly and bumpy forest region. The region is under the effect of typical Black Sea Climate which dominates the Region. Weather is cool in summer and warm in winter. The region is a high rainfall zone and the annual amount of precipitation observed between 730 mm ad 1680 mm. Regarding the precipitation and humidity, the lash flora covers the lands.

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FIGURE 2: The map of the project activity:

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A.4.2. Type and category(ies) and technology/measure of the small-scale project activity: Sectoral Scope 1: Energy Industries (renewable/non-renewable sources) Type I: Renewable Energy Projects Category I.D.: Renewable energy technologies that supply electricity to a grid. “This category comprises renewable energy generation units, such as photovoltaics, hydro, tidal/wave, wind, geothermal and renewable biomass, that supply electricity to and/or displace electricity from an electricity distribution system that is or would have been supplied by at least one fossil fuel fired generating unit” The project is a new hydropower plant, and the main construction consists of a conveyance tunnel measuring 3,640 meters, surge tank, a forebay, a penstock measuring 175 meters, two water intakes located at each end of the transmission tunnel, powerhouse switchyard and a tailwater canal. There are 3 water-turbine generator units in the powerhouse with an installed capacity of 4.5 MW each. The project makes use of water resources to generate electricity by leading the water through tunnel to the forebay and directing it through the turbine to drive the alternators. Electric power is produced in the alternator and will be subsequently delivered to Turkish National Grid via 1 km long, 34.5 kV transmission line. The project is expected to generate 46.89 GWh/year of electricity.

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A.4.3

Estimated amount of emission reductions over the chosen crediting period:

The fixed crediting period of 7 years is chosen for the project. The amount of annual and total emission reductions is shown in the following Table 3:

Years 2014 2015 2016 2017 2018 2019 2020 Total estimated reduction (tonnes of CO2) Total number of crediting years. Annual average over the crediting period of estimated reductions (tonnes of CO2)

TABLE 7: Annual estimation of emission reductions in tonnes of CO2 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 231,073.5 7 33,010.5

A.4.4. Public funding of the small-scale project activity: The project does not obtain public funding6. A.4.5. Confirmation that the small-scale project activity is not a debundled component of a large scale project activity: According to Appendix C of the Simplified Modalities and Procedures for Small-scale CDM Project Activities7, a proposed small-scale project activity shall be deemed to be a debundled component of a large project activity if there is a registered small-scale CDM project activity or an application to register another small-scale CDM project activity:

boundary of the proposed small-scale activity at the closest point. As a result of the careful studies that have been done on publicly available EPDK (Energy Market Regulatory Authority) website statistics and data8, there is only Incirli HEPP (28.53 MW) owned by the same project participant, MERTLER Enerji Uretim Pazarlama A.S., that the proposed project use the tailwater of. Since Incirli HEPP (25.20 MW) is a large scale CDM project activity and holds a different 6

Annex 2: ODA decleration.

7

please refer to Guidelines on assessment of de-bundling for SSC project activities at http://cdm.unfccc.int/Projects/pac/pac_ssc.html 8

http://www2.epdk.org.tr/lisans/elektrik/lisansdatabase/verilenuretim.asp

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electricity generation license other than the proposed project, the proposed project is not a debundled component of a large scale project activity. With respect to CDM project activity categorization that has been mentioned in the first paragraph of this section, also a crosscheck on Gold Standard and VCS databases has been completed and no registered/applied project activity had been determined which is owned by the proposed project’s owner or any other project activity within 1 km proximity with the proposed project activity Saray HEPP. In conclusion, Saray HEPP is not a debundled component of a large scale project activity. SECTION B. Application of a baseline and monitoring methodology

B.1. Title and reference of the approved baseline and monitoring methodology applied to the small-scale project activity: Title of the approved baseline/monitoring methodology and relevant tools9: AMS-I.D. – Grid connected renewable electricity generation, (Version 17) ‘Tool to calculate the emission factor for an electricity system’ (Version 02) ‘Tool for the demonstration and assessment of additionality’ (Version 05.2) ‘Combined tool to identify the baseline scenario and demonstrate additionality’ (Version 02.2) ‘Tool to calculate project or leakage CO2 emissions from fossil fuel combustion’ (Version 02)

B.2

Justification of the choice of the project category:

The proposed project falls into: Sectoral Scope 1: Energy Industries (renewable/non-renewable sources) Type I: Renewable Energy Projects Category I.D.: Renewable energy technologies that supply electricity to a grid. This category comprises renewable energy generation units, such as photovoltaics, hydro, tidal/wave, wind, geothermal and renewable biomass, that supply electricity to and/or displace electricity from an electricity distribution system that is or would have been supplied by at least one fossil fuel fired generating unit. The proposed project is a greenfield run-of-river hydropower project by using water resources for power generation. The electricity generated by the proposed project will be connected to Turkish National Grid, so it is a grid-connected electricity generation project from renewable sources. The

proposed project does not involve switching from fossil fuels to renewable energy at the site of the project activity. The

geographic and system boundaries for the Turkish National Grid can be clearly identified and information and data on the characteristics of the grid is available. 9

http://cdm.unfccc.int/methodologies/SSCmethodologies/approved.html

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 

B.3.

The project activity is not a combined heat and power (co-generation) system, The project activity has an output capacity lower than 15 MW the project has a total installed capacity of 13.5 MW Description of the project boundary:

As referred to in approved small-scale methodology AMS I.D Version 17, the spatial extent of the project boundary includes the project power plant and all power plants connected physically to the electricity system that the proposed project power plant is connected to , which is Turkish National Grid for the proposed project. The project activity will generate electricity and supply the energy demand not locally but throughout the whole country. The generated electricity of the proposed project activity will be connected and use the national grid transmission lines via the regional Electricity Distribution Company under the authorities of TEIAS (Turkiye Elektrik Iletim A.S. / Turkish Electricity Transmission Corporation) and TEDAS (Turkiye Elektrik Dagitim A.S. / Turkish Electricity Distribution Corporation). The project boundary consists of the physical project area components from the culvert, -deriving the water from the tailwater of Incirli HEPP’s tailwater canal- to the powerhouse and energy transmission line excluding the Incirli HEPP. FIGURE 3: The schema of the project boundary

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FIGURE 4: Turkish Energy Sector Structure of Government Bodies10

For the calculation of emission reductions, the only type of GHG included in this Project is CO2. The emissions sources included and excluded from the project boundary for determination of both baseline and project emissions are listed below:

Project

Baseline

Source Source: CO2 emissions from electricity generation in fossil fuel fired power plants connected to the Grid.

Source: Saray HEPP

Gas

Justification/Explanation

CO2

Included

CH4

Excluded

According to AMS I.D, only CO2 emissions from electricity generation should be accounted for. According to AMS I.D

N2O

Excluded

According to AMS I.D

CO2

Included Excluded (Due to the 0 project emission of the project activity) Excluded


CH4

N2O

10

TABLE 8: Included?



http://www.teias.gov.tr/eBulten/makaleler/2008/12%20ulusal/12.smpozyum%20bildirisi.htm

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B.4.

Description of baseline and its development:

The baseline scenario is as follows:

This project follows the methodology described in the AMS I.D.,Version 17. Selected methodology has been applied together with the “Combined tool to identify the baseline scenario and demonstrate additionality” (Version 02.2), “Tool to calculate the emission factor for an electricity system, (Version 02) and “Tool for assessment and demonstration of additionality, (Version 05.2). In the methodology, the baseline scenario has been identified as “If the project activity is the installation of a new grid-connected renewable power plant/unit, the baseline scenario is the electricity delivered to the grid by the project activity that otherwise would have been generated by the operation of gridconnected power plants and by the addition of new generation sources” and this is applicable for the project activity since it is a Greenfield plant. projected in Figure 4, other than auto-producers, all the electricity production both in private sector and public sector subject to sales is delivered to the Turkish National Grid. Therefore the baseline scenario has been determined as Turkish National Grid for the proposed 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 small-scale CDM project activity: Assessment and demonstration of additionality According to the methodological tool “Tool for the demonstration and assessment of additionality” (Version 05.2), why were a step-wise approach had been adopted in order to prove the additionality of the proposed project. 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 economically or financially attractive, or 2) not economically or financially feasible;  Barrier analysis (optional); and  Common practice analysis

Step 1: Identification of alternatives to the project activity consistent with mandatory laws and regulations Sub-step 1a: Define alternatives to the project activity: The possible alternative scenarios to the project that provide outputs or services comparable to the proposed project activity have been identified as directed by the “Combined tool to identify the baseline scenario and demonstrate additionality” (Version 02.2) 1. Implementing the Project, but not as a VER project; 2. Providing the same amount of electricity by the Turkish national grid; 3. Building a new thermal power plant with the same installed capacity or equivalent electricity output; 4. Building a power plant using other renewable sources with the same installed capacity or equivalent electricity output.

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Scenario 1: Implementing the Project, but not as a VER project: Based on the investment analysis performed in Section B.5, .The equity IRR of the project without the voluntary emission reduction (VER) revenues is 3.12%, which is much lower than the benchmark IRR of 7.64%11. The proposed project becomes relatively feasible with VER revenues as the equity IRR increases to 4.25%. Thus, Scenario 1 is not feasible but will be compared to the project activity. Scenario 2: Providing the same amount of electricity by the existing power plants connected to Turkish National Grid This scenario represents the default option of current practice. Hence it is a credible and realistic scenario. However the current electricity system is dominated by natural gas, coal and lignite12; producing large amount of GHG emission as highlighted by emission factor of 0.704 tCO2e/MWh13. This is the baseline scenario chosen for the project activity. Scenario 3: Building a new thermal power plant with the same installed capacity or equivalent electricity output; Turkish electricity generation is mainly composed of thermal power plants. Based on the recent data, the share of hydroelectric power plants on electricity generation has been quite unstable and could not sustain an accelerated development which is clearly seen in the table below:

TABLE 9: Annual Energy Generation Development of Turkey14 Years 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Hydraulic Energy Generation (GWh) 34677.5 30878.5 24009.9 33683.8 35329.5 46083.7 39560.5 44244.2 35850.8 332614.52 35958.4

Total Energy Generation (GWh) 116439.9 124921.6 122724.7 129399.5 140580.5 150698.3 161956.2 1762914.52 191558.1 198418.0 194812.9

Total Increase (%) 4.9 7.3 -1.8 5.4 8.6 7.2 7.5 8.9 8.7 3.6 -1.8

Since Turkey is classified as a developing country, obviously there is an increasing demand for electricity which is fully being expected to continue in the near future.

11

Please refer to Section B.5 for the benchmark calculations.

12

Please refer to Figure 3 for Turkish energy generation mix.

13

Please refer to Section 3 for emission factor calculations.

14

http://www.teias.gov.tr/istatistik2009/13.xls

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The current trend in Turkey -considering historical data on slow development of alternative energy resources -is to build increasing numbers of thermal power plants in the future to satisfy the annual growing demand in energy. In conclusion it is correct to state that in the absence of the proposed project activity, the same amount of electricity is required to be supplied via either the current power plants or by increasing the number of thermal power plants thus increasing GHG emissions. Thus, the alternative is realistic and credible as well. However due to the competitive nature of the market there is no publicly available data to compare the project activity to this Scenario therefore this scenario is excluded. FIGURE 3: Turkish Energy Generation Mix15

As indicated in the 2008-2018 electricity generation capacity projection that has been published by TEIAS, it has been envisaged that starting from 2012, the annual electricity consumption demand will be increased maximum by 7.5% and minimum by 6.7%. Considering the total installed capacity of Turkey was 41,821.2 MW back in 200816,   

If no new power plants step in and the demand would be met by the presently operating facilities, by 2011,the national electricity supply shortage grow to be -4.1% and thrive permanently. If all the process-under-construction power plants get activated and start to generate electricity, by 2011, the national electricity supply shortage still grow to be -3% and thrive permanently. If all the process-under-construction projects, presently operating power plants and the license holding projects in the planning phase start electricity generation simultaneously, the supply shortage scenario mentioned above will be delayed to 2015 by -3.5%.

15

http://www.enerji.gov.tr/index.php?dil=tr&sf=webpages&b=elektrik&bn=219&hn=219&nm=384&id=386

16

http://www.teias.gov.tr/projeksiyon/KAPASITEPROJEKSIYONU2009.pdf

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

In order not to encounter any electricity supply shortage by 2020, 56,000 MW extra installed capacity shall be erected.

There are two possible scenarios that have been projected on the potential power plant installed capacities of thermal, hydraulic, wind and other renewable resources. Scenario 1:

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

THERMAL MW 27905 27683 28966 29574 32653 32653 32653 32653 32653 32653

THERMAL MW 27905 27750 28966 32094 34142 34142 34142 34142 34142 34142

% 64 62 61 59 62 62 62 60 60 60

HYDRAULIC MW 14736 16100 17726 19320 19320 19320 19320 20520 20520 20520

% 64 62 60 60 62 62 62 61 61 61

HYDRAULIC MW 14886 16381 18058 19877 19877 19877 19877 21077 21077 21077

% 34 36 37 39 36 36 36 38 38 38

WIND + RENEWABLE MW % 655 2 857 2 1067 2 1067 2 1067 2 1067 2 1067 2 1067 2 1067 2 1067 2

TOTAL MW 43295 44640 47760 49962 53040 53040 53040 54240 54240 54240

% 34 36 37 37 36 36 36 37 37 37

WIND + RENEWABLE MW % 695 2 880 2 1157 2 1157 2 1157 2 1157 2 1157 2 1157 2 1157 2 1157 2

TOTAL MW 43485 45011 48182 53128 55182 55182 55182 56382 56382 56382

Scenario 2:

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

As being supported and highlighted by the numbers above, thermal power plants in Turkey are and will be the leading actor among the electricity generation supply system. Therefore it can be determined that the electricity generated by the project activity that is supplied to the grid is or would have been supplied by at least one fossil fuel fired generating unit.

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GRAPH 1: Peak Load and consumption projection for Turkish electricity system between 2005-202017

Scenario 4: Building a power plant using other renewable sources with the same installed capacity or equivalent electricity output. In Trabzon province where the proposed project activity is located, electricity generation from hydro power is a pervasive private investment area. Regarding the list of power plants that is published by EPDK, in Trabzon, it is clearly seen that the HEPPs are the only electricity production facilities in the province. There are 59 hydroelectric power plants that are granted with generation licenses and 43 of them are already implemented and operational. As a result, the region is not convenient for the alternative renewable energy generation, wind, and the proposed project is definitely unfit for this scenario. Therefore, Scenario 4 is neither a credible nor a realistic baseline scenario up to dated. According to the alternatives above, Scenarios 1 & 2 are the most realistic and credible baseline scenarios for the proposed project activity. Outcome of Step 1 a: Identified realistic and credible alternative scenarios to the project activity:

17

http://www.teias.gov.tr/apkuretimplani/veriler.htm

21



Based on the baseline scenario discussion in the parts above, alternative scenario number 4 is not applicable for the project activity due to lack of resources for other renewable energy18. Alternative scenario number 1 and 2 are applicable to compare to the project activity and alternative scenario number 2 is chosen as the baseline. Alternative scenario number 3 is also not applicable due to the lack of publicly available information and particular data. Sub-Step 1 b. Consistency with mandatory laws and regulations: To conclude the above discussions in Sub-steps 1a and 1b, alternative scenarios 1 and 2 that are discussed above are technically feasible and also comply with current consent conditions in Turkey. Consistency with mandatory laws and regulations of the project activity: The project activity complies with current consent conditions in Turkey. The proposed project has been implemented in terms of legal compliance with the law codes and public entities as explained below: Through the cabinet decree #93/4789 ratified in 12.08.1993, the state-owned enterprise TEK (Turkish Electricity Administration) was recognized in two separate enterprises as TEİAŞ (Turkish Electricity Generation, Transmission Co.) and TEDAŞ (Turkish Electricity Distribution Co.). By the Law # 4501, ratified in 21.01.2000; an international arbitration committee was settled in the sector. The main duty of this committee was to prepare eligibility regulations on the current electricity legislations through the UN legal acquisitions and in accordance with this to start the restructuring surveys in the sector. As the result of this restructuring programme, Electricity Market Law # 4628, date 20.02.2001 was ratified. The aim of this law is; to create an electricity market that can activate in a competitive environment with special legal system legislations, which is financially strong, consistent and transparent to provide the consumers the most efficient, qualified, constant, low cost and environment friendly electricity. With the contribution of the private sector companies, the privatisation of this competitive market aimed to identify, regulate and control the legal, technical and financial criteria of the electricity companies. In 2001, Electricity Market Regulatory Committee (EPDK) 19 was set up to oversee the generation of the new power market. EPDK has the leading role for the implementation of the overall power reform and completed an initial draft of regional market rules. As the initial step of starting an open electricity market, the Turkish government began to encourage the private sector companies to invest in power generation projects. However, the tariff determination and approval of power project investments are still centrally controlled and manipulated by EPDK as of January 1st, 2005. EPDK is a self-contained supreme board. Even though it is a public institution, it is not under the jurisdiction of the government.

18

http://www.google.co.uk/imgres?imgurl=http://www.dmi.gov.tr/FILES/arastirma/ruzgaratlasi/107_tra9mart.jpg&imgrefu rl=http://www.dmi.gov.tr/arastirma/yenilenebilir-enerji.aspx%3Fs%3Druzgaratlasi&usg=__YII8grqzgIizaymrxc-J_GVtY0=&h=509&w=700&sz=71&hl=en&start=3&zoom=1&um=1&itbs=1&tbnid=amZeZxEBVbNxsM:&tbnh=102&tb nw=140&prev=/images%3Fq%3Dturkiye%2Bruzgar%2Bharitasi%26um%3D1%26hl%3Den%26sa%3DX%26rlz%3D 1T4ACGW_en___TR400%26tbs%3Disch:1 19

www.epdk.gov.tr

22



By December 29th, 2010, significant amendments have been settled in Renewable Energy Resources law. By the decree, the new tariff rates have been defined as dollar cent unit price instead of euro cent. For Hydro and wind facilities it has been specified as 7.3 dollar cent. For geothermal facilities 10.5 dollar cent, for biomass projects including the landfill gas 13.3 dollar cent and for the solar power systems the tariff has been set as 13.3 dollar cent as well. The ordinance applies for the projects that are implemented and operational or will be operational as of 18/05/2005 until 31/12/2015, for ten years. In addition, for the machinery and electromechanical equipment that are manufactured in Turkey, the facility has been granted “Local Content” varying between 0.4 dollar cent and 2.4 dollar cent based on the type of the energy generation resources.20 As being indicated above, Turkish electricity market is at the beginning stage shifting from governmentoriented system to market-oriented system by various incentives to encourage the private investors. All the instabilities and uncertainties accompanied with the reforms could lead to critical and risky business conditions for the power producers to invest in Turkey. Hence, at present, investors prefer the coal-fired power plants associated with mature domestic technology, abundant fuel source with preponderant site location, shorter construction period, and low unit capacity construction cost. Regarding the above information on the current electricity market situation, the above alternatives for the project implementation are realistic and credible. The following applicable mandatory laws and regulations have been identified concerning renewable energy investments in Turkey: 1. Electricity Market Law21 2. Law on Utilisation of Renewable Energy Resources for the Purpose of Generating Electrical Energy22 3. Energy Efficiency Law23, 4. Forest Law24, 5. Environment Law25 6. Regulation on procedures and principles of signing the agreement of utilisation of water resources for the purpose of electricity production in the electricity market 26 7. Regulation on Environmental Impact Assessment27 Outcome of Step 1 b: The resultant alternatives to the project as outlined in Step 1a are in compliance with all these mandatory legislation and regulations taking into account the enforcement in the country and UNFCCC Executive Board decisions.

20

www.epdk.gov.tr

21

Law Number 4628, enactment date 03/03/2001, http://www.epdk.gov.tr/english/regulations/electricity.htm

22

Law Number 5346, enactment date 18/05/2005, http://www.eie.gov.tr/duyurular/YEK/LawonRenewableEnergySources.pdf 23

Law Number 5627, enactment date 02/05/2007, edhttp://www.eie.gov.tr/english/announcements/EV_kanunu/EnVer_kanunu_tercüme_revize2707.doc 24

Law Number 2872. Published in Official Gazette No:18132 on 11/08/1983.

25

Law Number 2872. Published in Official Gazette No:18132 on 11/08/1983. It will be available upon request.

26

National Gazette Number 25150, 06/06/2003 National Gazette Number 26939, 17/07/2008

27

23



TABLE 10: The timeline of the project is as follows: Events Feasibility Study Report (13.5 MW) Water Usage Agreement with DSI (11.6 MW) Project Introductory File28 Environmental Impact Exemption Letter granted by Governorship of Trabzon (13.5 MW) Electricity Generation License obtained from EPDK (11.6 MW) Application for license amendment on ownership of the project activity License amendment approval for Mertler Enerji Uretim Pazarlama A.S. Water Usage Rights Agreement Appendix amendment for the Installed Capacity (13.5 MW) License amendment for installed capacity and the annual electricity generation (13.5 MW)

Date May 2010 July 8th, 2010 March 2011 March 17th,2011 April 14th, 2011 May 17th, 2011 July 15th, 2011 October 25th, 2011 September 9th, 2011

Step2: Investment Analysis An investment analysis has been carried out in order to make an economic and financial evaluation of the proposed project. It should be noted that no ODA has been provided for the project investment. The purpose of investment analysis is to determine whether the project activity is the most economically or financially attractive or less than other alternatives without the revenue from the sale of VERs. To conduct the investment analysis, following sub-steps are used: Sub-step2a: Determine appropriate analysis method Three methods of analysis are suggested in the Tool for the Demonstration and Assessment of Additionality. They are: simple cost analysis (Option I), investment comparison analysis (Option II) and benchmark analysis (Option III). Option I: Simple cost analysis. This analysis method can be used if the project activity produces no economic benefits other than CDM related income. However, this option is NOT applicable to the project for the reason that the project activity generates the revenue from the sale of electricity generation. Option II: Investment comparison analysis. The investment comparison analysis has been excluded. The reason is, given by the defined alternatives, that the only realistic and creditable alternative, i.e. the baseline scenario, is the continuation of electricity supply from the existing national power grid to meet the electricity demand other than a new power investment project. Option III: Benchmark analysis. After determining the financial/economic indicator, such as IRR, as it has been permitted by the additionality tool, the value shall be assessed considering the parameters that are standard in the market by also regarding the specific characteristics of the project type. However this

28

Due to the geographical borders of the project activity, the project location has been revised to Trabzon Province. In Feasibility Study Report, it has been indicated as Rize Province.

24



financial analysis shall not be linked to the subjective profitability expectation or risk profile of a particular project developer. The benchmark analysis method is adopted based on the consideration of the WACC of the proposed project. Sub-step 2b: Option III. Apply benchmark analysis As it has been pointed towards to in the “Tool for the demonstration and assessment of additionality” under sub-step 2b, article 6, paragraph (a): Discount rates and benchmarks shall be derived from “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.” Accordingly, under the guidance of ‘Annex: Guidance on the Assessment of Investment Analysis’, paragraph number 11, it has been defined as required/expected returns on cost of capital are appropriate benchmarks for a project IRR. The analysis will be held accordingly in the following parts. As being stated above, the benchmark is the WACC of the project which is referred as the weighted average of cost of capital which has been permitted in the “Tool for the demonstration and assessment of additionality” under sub-step 2b, article 6, paragraph (c): A company internal benchmark (weighted average capital cost of the company), only in the particular case referred to above paragraph 5 (economic analysis shall be based on standard parameters of the market but not linked to subjective profitability expectation or risk profile of a particular project developer) supported by Annex: Guidelines on the Assessment of Investment Analysis (Version 03.1), Article 12. According to the 11th Article of Annex: Guidelines on the Assessment of Investment Analysis (Version 03.1): “Due to the impact of loan interest on income tax calculations it is recommended that when a project IRR is calculated to demonstrate additionality a pre-tax benchmark be applied.” In this case a pre-tax benchmark is applied. Therefore following the WACC formula below, the income tax calculation (1-Tc) is by-passed. “ In cases where a post-tax benchmark is applied the DOE shall ensure that actual interest payable is taken into account in the calculation of income tax. In such situations interest should be calculated according to the prevailing commercial interest rates in the region, preferably by assessing the cost of other debt recently acquired by the project developer and by applying a debt-equity ratio used by the project developer for investments taken in the previous three years” In this case, since the project if a Greenfield investment and the financial agreements are not initiated yet, regarding the provision above, it has been perceived conservative to take into account of Incirli HEPP’s interest rate and debt/equity ratio to apply in the calculations below.

25



WACC formula29:

Indicators and Values for WACC Calculation30:

WACC of the investment: 7.64% E/V= Rate of the equity in the investment which is 27.20% in this case. Re= Cost of Equity : 18.37% D/V= Rate of the debt in the investment which is 72.80% in this case. Rd= Cost of debt (in this case it is the interest rate of 3.64% )

Cost of Equity Formula:

Indicators and their values for Cost of Equity Calculation31: Risk Free Rate32: 4.20% Country Risk Premium: 4.13% Sovereign Spread multiplied by Volatility Constant : 2.75% x 1.5 = 4.13% Volatility constant: Standard deviation of daily per cent changes in the equity market divided by the standard deviation of daily per cent changes in bond market33: 1.5

29

http://www.mtholyoke.edu/~aahirsch/howwacc.html

30

Excel workbooks for the WACC, Adjusted and Levered-Unlevered Betas, Cost of Equity and Volatility calculations are available upon request 31

Excel workbooks for the Adjusted and Levered-Unlevered Betas, Cost of Equity and Volatility calculations are available upon request 32

http://www.treasury.gov/resource-center/data-chart-center/interestrates/Pages/TextView.aspx?data=longtermrateYear&year=2011

26



Sovereign spread: The sovereign spread represents the difference between bond yields issued on international markets by the country in question versus those offered by Moody’s ratings34: 2.75% Computed mature market risk premium multiplied by levered and adjusted Beta: 5% x 2.008602=10.04% Mature market risk35: 5.00 % Adjusted36 and Levered37 Beta of the project investment: 2.008602 Debt/Investment Ratio of Incirli HEPP that is applied for the proposed project: 78.80 / 27.20 Cost of Equity: RFR + MMP + CRP = 18.37 % Explanation of the variables: Risk free rate represents an after tax return over all components of the country’s major index. This is the amount obtained from investing in securities considered free from the market risk, such as government bonds from developed countries. The risk free rate has been estimated via Long Term Composite US T-Bonds as 4.20% by the start date of the investment January 14/04/201138. The country risk premium has been calculated by the multiplication of the sovereign spread39 and the volatility constant40. As the time range, 1094 days before the start date of investment, between 15/04/2008 and 14/04/2011 has been adopted in order to reflect the investment climate prior to the investment decision. Volatility is computed by dividing the annualized standard deviation of daily percent changes in the equity market index, ISE 100 (Istanbul Stock Exchange) to the annualized standard deviation of daily percent changes of randomly chosen long term four dollar denominated Turkish Government Bonds41. Regarding to Turkish financial market movements, the available historical data of trading days in 1093 days before the investment start date is a conservative time period to project the averaged volatility constant for the particular investment. 33

Bloomberg database: Istanbul Stock Exchange (ISE) equity market index and Randomly chosen USD denominated long-term bonds: US900123AX87, US900123BA75, US90012AZ36, US900123AV22 via the method from http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/ctryprem.html 34 35 36

http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/ctryprem.html http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/ctryprem.html The Beta Adjustment method definition is available upon request.

37

http://www.ibankingfaq.com/interviewing-technical-questions/discounted-cash-flow-analysis/what -are-theformulas-for-ulevering-and-levering-beta/ 38

http://www.treasury.gov/resource-center/data-chart-center/interestrates/Pages/TextView.aspx?data=longtermrateYear&year=2011 39

http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/ctryprem.html, indicated by Moody’s rating.

40

Bloomberg database: IMKB equity market index and Randomly chosen USD denominated long-term bonds: US900123AX87, US900123BA75, US90012AZ36, US900123AV22 via the method from http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/ctryprem.html 41

Bloomberg database: IMKB equity market index and Randomly chosen USD denominated long-term bonds: US900123AX87, US900123BA75, US90012AZ36, US900123AV22 via the method from http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/ctryprem.html

27



In the calculations, daily mid-current yield changes of the bid prices and the ask prices of the bonds were embedded in standard deviation method and averaged according to the method. Beta measures how much a company's share price moves against the market as a whole. A beta of one, for instance, indicates that the company moves in line with the market. If the beta is in excess of one, the share is exaggerating the market's movements; less than one means the share is more stable. Since the project owner does not exist in the equity market, four ISE 100 utility members’ betas in Turkish energy industry have been considered as the indices. The Hamada Formula42 has been adopted for adjusting the leverage factor. Following the ‘Pure Play Method’43, these betas are raw levered beta’s of the four electricity members of the ISE 10044. The betas have to be unlevered according to their debt/equity ratios according to the formula in order to exclude the particular financial aspects on company basis45. For the time range, the interval between the project start date and 04/14/2008 has been adopted in order to have a conservative approach. Regarding the Turkish financial market movements, the available historical data of trading days in 1094 days before the investment start date is a rational time period to provision the Beta activity profile for the particular sector of investment. Then the unlevered raw beta values are levered; this time according to the project activity’s debt/equity ratio and then adjusted according to the beta adjustment method46. The reason of adjustment is that theoretically the company beta will match the total market beta in the future, which is 1.00. Therefore the adjustment brings the beta value closer to 1.00 for a realistic future financial projection for financial performance. Applying these variables into the cost of equity formula above, the cost of equity of 18.37% is obtained. As the expected return of the proposed project’s investment containing the total investment consisting of the financial loan and the equity, WACC, the benchmark is set as 7.64%. Sub-step 2c. Calculation and comparison of financial indicators The main assumptions of the project’s IRR calculations are summarized in the table below.

42

“Ascertaining the divisional beta for project evaluation –the pure play method- a discussion”, article by N. R. Parasuraman, The Chartered Accountant, November 2002 Publication. Available upon request. 43

“Ascertaining the divisional beta for project evaluation –the pure play method- a discussion”, article by N. R. Parasuraman, The Chartered Accountant, November 2002 Publication. Available upon request. 44 45 46

: Bloomberg Beta analysis screenshots between the range of 14/04/2008 – 14/04/2011 is available upon request. Debt/Equity ratios of the Energy Companies are available upon request Adjusted Beta Formula of Bloomberg Database is available upon request.

28



TABLE 11: Data and indicators for financial analysis: Parameter Annual assumed gross electricity supply

Unit

Value

Data Source

kWh/y

46,890,000

FSR

Electricity sales tariff

$cent/kWh

7.3

Total investment 1 USD Annual O&M costs Annually paid contribution margin amount to DSI for water usage rights per kWh electricity production Depreciation factor Crediting period

USD TL USD

25,156,346 1.6 199,601

TL

0.01

Year

0.09063 7

2010 Gold Standard tariff rate

USD

8.1

Annual Emission Reductions Emission Factor

tCO2e tCO2e/MWh

30,010.56 0.704

Renewable Energy Law47 FSR FSR48 FSR Section 8 Water Usage Rights Agreement Article 28/A FSR Section 8 VCS regulations Bloomberg – New Energy Finance 49 PDD B.6 PDD B.6



The inflation adjustment and accountings are exempted from IRR and benchmark calculations. First and second articles of law no. 5024 published in the Official Gazette No.25332 on 30 December 2003 requires the application of inflation accounting in Turkey in 2004 and future years. However since the implementation of IFRS in Turkey50 as of 2005, the inflation adjustment resolutions described in law no.5024 have not been realised as of December 200551. Since then, the financial statements in Turkey are not in accordance with the inflation accounting principles and neither the proposed project’s financing.



The Value Added Tax of the project’s electricity sales to TEIAS has not been considered in the IRR calculations. Even though the amount in the monthly invoice is 18% VAT inclusive, it is observed in the monthly tax statement, the VAT charged to TEIAS is being reduced from the VAT that the project owner has to discharge to the government. The final net settlement renders the VAT calculations to be excluded from the IRR calculations of the project activity.

According to the IRR calculation52, the project IRR values of the project are summarized in Table 4.

47

www.epdk.gov.tr/mevzuat/diger/yenilenebilir/yenilenebilir.doc

48

Section 8-1. DSI determined January 2010 exchange rate.

49

Carbon Markets Research Note – 11 February 2011

50

www.tmsk.org.tr/.../TMSK-26102006XVII1muhkongresikonusmatasİNG.doc

51

http://www.tcmb.gov.tr/yeni/mgm/denetim2005/THPING2005.pdf

52

IRR Workbook available upon request.

29



TABLE 9: IRR of the project activity: Parameter Project IRR

Without VER Revenues 3.12%

With VER Revenues 4.25%

Benchmark 7.64%

Benchmark Analysis: Since there is no objective, official and publicly available pre-determined value for IRR or any other financial indicator for hydro power plants in Turkey and according to the "Tool for the demonstration and assessment of additionality" sub-step 2b, article 6 (c), a relevant benchmark for a Project’s IRR can be derived from the weighted average capital cost of the company. The calculation methods for the benchmark value below have been based on finance professionals’ advice and accepted accounting and mathematical methods. A reliable risk premium related to hydro power projects in Turkey could not be identified due to a lack of public information in this sector. Energy sector projects face overall levels of risk that may be higher than other sectors of economy, and hydro power plants specifically face significant levels of performance risks, related to uncertain climatic factors. Additionally, there are risks associated with the fact that hydro technology, when compared to conventional thermal power generation, has a high capital cost and low load factor, which result in low financial rates of return. This suggests that a realistically pre-tax calculated weighted average cost of capital of 7.64% is the threshold for this investment, suggesting that this approach is a commonly used analysis method whether to decide if the investment is worth making and promising a profitable turnover. Project IRR of the SARAY HEPP has been calculated as 3.12% based on the parameters given above without considering the carbon revenue. Project IRR has been calculated considering the sales revenue, OM costs and fixed asset investment as stated in the applied tool and guidelines. Electricity tariff has been applied as $7.3 Cent/kWh. Although this is the maximum feed-in-tariff as given in renewable energy law53, it has been chosen to do so in order to highlight the unattractive IRR outcomes regarding the benchmark. Annual electricity generation has been taken as 46,890,000 kWh. As “Tool for the demonstration and assessment of additionality” Annex 58, 3rd article directs that the IRR calculation can be limited by the investment depreciation period and it is 10 years in this case. Therefore the IRR calculation range is 13 years and conservative regarding the minimum 10 years threshold which is indicated in the same article. As it is indicated in the 4th article, the leftover value after the time of depreciation has been included in the inflow values of the IRR cashflow. Since due to the impact of loan interest on income tax calculations it is recommended that when a project IRR is calculated to demonstrate additionality a pre-tax benchmark be applied.Thus, the income tax calculations have been neglected in IRR calculations as well. The IRR value represents an actual estimation of the realistic set of outcomes in terms of capital investment, OM costs, electricity sales price and electricity generation. The IRR of 3.12%, when compared to the 7.64% benchmark, it has seen that the project is not financially attractive for investors as the weighted average cost of capital is the accepted threshold for the investment to be financially relatively feasible. When we include the carbon revenue in the cash flow, the project IRR increases to 4.25% and the project becomes more attractive and viable for the investors. Particularly for this proposed project, the carbon crediting revenues results in 36.21% increase for the project IRR, which is concluded as a significant support for the investment.

53


30



Since the project IRR is below the WACC, the project VER revenue greatly enables the project investor to obtain loan finance. The project owner will also benefit from the following intangible benefits that VERs provide such as;  Development of economical cooperation on international arena which is appreciating the greenhouse gas reductions that will positively affect investor’s confidence.  Enhanced corporate green image of the project owner through its contribution to a clean source of electricity and the diversification of electricity sources in Turkey, which broadens stakeholder’s confidence and vision. Additionality of the Project The IRR of the proposed project is 3.12% (without VER revenues) with a tariff of 7.3 $cent/kWh, as indicated in the renewable energy law, by applying the following conservative input values:    

Annual electricity sales revenue Capital investment costs OM Costs Fair value included as a cash inflow in the final year at the end of the assessment period.

Outcome of Sub-step 3c: IRR remains below the benchmark of 7.64%. Therefore it is concluded that the proposed project is additional. Sub-step 2d. Sensitivity analysis The sensitivity analysis shall show whether the conclusion regarding financial attractiveness is robust to be reasonable variations in the critical assumptions. Following key parameters have been selected as sensitive indicators to test the financial attractiveness for the project.    

Capital Investment Costs, Operation and Maintenance Costs, Electricity Generation, Electricity Sales Tariff

31



By a coefficient of ±10%, fluctuations in parameters above, the various IRR calculations are projected in the table below. TABLE 10: Sensitivity Analysis for Saray Project

Fluctuating Indicators Investment Costs

O&M Costs

Electricity Sales Tariff

Electricity Generation

%

-10% 4.95

Fluctuations 0 3.12

+10% 1.55

%

6.16

4.25

2.60

%

3.24

3.12

3.01

%

4.36

4.25

4.14

%

1.08

3.12

5.04

%

2.25

4.25

6.13

%

1.26

3.12

4.88

%

2.43

4.25

5.97

IRR

Unit

Project IRR P. IRR with CR Project IRR P. IRR with CR Project IRR P. IRR with CR Project IRR P. IRR with CR

In order to reach 7.64% threshold as the benchmark points to, either the electricity sales tariff must be increased by 24% to attain 7.55% project IRR or else the annual electricity production of the project must increase by %27 to reach project IRR of 7.67. The reason of the variation between tariff increase and electricity production increase is the DSI contribution margin that is paid regarding the electricity production of kwh/y. Otherwise, the capital investment expenses shall be diminished 22% in order to obtain 7.58% project IRR. The indicators of the sensitivity analysis are separately examined below. Annual electricity production In order to increase the electricity sales, the electricity production and the annual operating hours of the project must be increased. However in practice, it is unrealistic to provision a constant additional increase of 27% annual electricity production due to the run-of-river technology of the project. Since the project doesn’t have a water storage component, the project’s energy generation potential is fully dependant on the water amount and flow regime of the source. Due to its nature of the current profile, the run-of-river projects cannot reserve any amount of water, and therefore energy. The project has been designed regarding to the average expected flow rate of Incirli HEPP’s tailwater. The designed average flow rate for the project and Incirli HEPP is determined via Simsirli Stream Gagging Station (no:2218) observations between 1963 and 2009 for 47 years. The analysed data was stored on daily, monthly and yearly basis. Incirli HEPP is designed to release (5.5 m3/s) water to the riverbed without deriving its energy in each period of the year. Saray HEPP is directly dependant on the tailwater of Incirli HEPP and considering the water amount of the inflow, the average flow rate of Saray HEPP is determined as 62.0 m3/s.

32



FIGURE 5: Average Inflow Amount of the Proposed Project54

In this case, it can be determined that the electricity generation of the project is fully dependant on the precipitation and evaporation amount of the drainage area which nourishes the stream. The project planned with the designed flow rate of 60 m3/s for 13.5 MWe installed capacity, concerning the determinant factors above particularly for the project activity. According to the flow rate permanency calculations, regarding to the obtained historical data by having a constant increase of 27% on the designed flow rate and the PLF of the project and move it up to 76.2 m3/s is very unlikely to achieve as it is projected in the graph below: FIGURE 6: The extreme and average monthly flow rate calculations on Iyidere stream between the years of 1963 and 2009.55

54

FSR Section 4

55

FSR Section 4

33



As being specified in the graph above, when both the mean and the median are examined, it is highly unlikely to prescribe a constant raise of 27% in the average flow rate of the project as the flow rate exceeds the threshold of 76.2 m3/s only three consecutive months in a year regarding the 47 years of historical data. Regarding this ratio, is not probable to provision an absolute, fixed increase of 30% for the electricity production which requires the same amount of change in the flow rate in consecutive years. Therefore it is not probable to envision a continuous substantial increase for the electricity production that is served to the grid, in order to enhance the equity IRR upwards. Tariff In order to reach the benchmark of 7.64% keeping the electricity production amount as it is, the feed-in tariff of the project has to be as 9.2710 $cent/kWh, with an increase rate of 27% of the officially defined maximum tariff to reach the project IRR of 7.67. To address the concerns recently raised by the EB, such as EB49, para 48, EB53, Annex 32, the policy changes which impact the tariff applicable to the project activity are determined and the highest tariff of the region is applied to the sensitivity test as the Renewable Energy Law directs to56. Prior to 2002, private enterprises in energy generation sector in Turkey were rare and the agreements on purchase guarantees and tariff rates were confidential between the project owner and the government. Policy Changes As the Renewable Energy Law had come into effect by 2005, 5.5 €cent/kWh of tariff rate for purchase guarantee has been established. By January 10th, 2011, it has been revised as 7.3 $cent/kWh. As the purchase rates are fluctuating daily regarding to the open market policy of the distribution companies, it is highly uncertain to be able to obtain a highest tariff rate. However it is obvious that 9.2710 $cent/kWh is a highly contradicting tariff rate to estimate for the project to reach regularly and base its economic expectations on. Annual O&M costs The annual O&M costs do not have a significant impact to the Project IRR. Even the annual O&M costs deteriorate to 0 from 199,601 USD, the IRR value of 3.12% without VER revenues and 4.25 with VER revenues only increases to 4.25% without VER revenues and to 5.36% with VER revenues staying almost 3 point down of the benchmark. Operating expenses (OPEX) are defined as the ongoing spending for running a business. In this case, OPEX majorly includes the salary and wages57. As opposing the decline of O&M cost scenario, the most recent salary index of Turkey in the 3rd quarter of 2008, the increase on government worker’s salary is ranked by 9.9%58, which is in the reverse direction of the required threshold of containing the O&M costs zero.

56


57

http://en.wikipedia.org/wiki/Operating_expense

58

www.tuik.gov.tr/PreHaberBultenleri.do?id=2087

34



Hence, it can be concluded that the annual O&M costs is not a real-life sensitive indicator that can be presumed to impact the project yield. In addition, according to FSR59, the relevant government bodies conclude that the O&M costs cannot be considered as zero for such an investment profile. Total Fixed Asset Investment Bearing in mind of 7.64% benchmark, the project IRR would reach 7.58% when the total fixed asset investment cut by 22%. However since the project is still on the planning phase, a careful analysis on the total fixed asset investment ratings has been undertaken. According to the most recent news bulletin of TUIK (Turkiye Istatistik Kurumu – Turkish Statistical Institute), it has been declared that the construction expenditure index has increased 1.57% in the fourth quarter comprising the months of October, November and December 2010 compared to the previous quarter. The index has been increased 7.52% compared to the fourth quarter data of 2009 and 5.75% compared to the four quarter averages60. Considering that the construction expenses are the major component of the total fixed asset investment for the project’s financial profile, it can be concluded that it is more realistic to provision a boost for this investment rather than a cutback of 22%. Regarding to the financial calculations and provisions, the investment amount has been conservative and sufficient for a project like this. Outcome of Step 2d: The proposed project activity is unlikely to be the most financially/economically attractive as indicated in the ‘Tool for Demonstration and Assessment of Additionality’ (Version 05.2), as per Step 2c para 10 b. Step 3. Barrier Analysis According to the ‘Tool for Demonstration and Assessment of Additionality’ (version 05.2), Step 3 is not applicable (only step 2 is selected). Step 4. Common Practice Analysis The project falls into small scale CDM project, the common practice is not necessary to be presented as per Attachment A to Appendix B of the ‘Simplified Modalities and Procedures for Smallscale CDM Project Activities’. Outcome of the Investment Analysis: The proposed project activity is unlikely to be the most financially/economically attractive as indicated in the ‘Tool for Demonstration and Assessment of Additionality’ (Version 05.2), as per Step 2c para 10 b. Therefore the proposed project is additional.

59

FSR, Section 9

60

http://www.tuik.gov.tr/PreHaberBultenleri.do?id=8426

35



B.6.

Emission reductions: B.6.1. Explanation of methodological choices:

The consolidated methodology AMS I.D. (Version 17) is applied in the context of the project in the following four steps: 1. Calculate the project emissions; 2. Calculate the baseline emissions; 3. Calculate the project leakage; 4. Calculate the emission reductions. 1) Project Emissions: According to the consolidated methodology ACM0002 “For most renewable power generation project activities, PEy = 0. However, some project activities may involve project emissions that can be significant. These emissions shall be accounted for as project emissions by using the following equation:” PEy =PE FF,y ,+PE GP,y + PE HP,y Where: PE y = Project emissions in year y (tCO2e/yr) PE FF,y = Project emissions from fossil fuel consumption in year y (tCO2/yr) PE HP,y = Project emissions from water reservoirs of hydro power plants in year y (tCO2e/yr) PE GP,y = Project emissions from the operation of geothermal power plants due to the release of non-condensable gases in year y (tCO2e/yr) Emissions from water reservoirs of hydro power plants (PE HP,y) For hydro power project activities that result in new reservoirs and hydro power project activities that result in the increase of existing reservoirs, project proponents shall account for CH4 and CO2 emissions from the reservoir, estimated as follows: (a) If the power density of the project activity (PD) is greater than 4 W/m2 and less than or equal to 10 W/m2:

Where: PEHP,y = Project emissions from water reservoirs (tCO2e/yr) EFRes = Default emission factor for emissions from reservoirs of hydro power plants in year y (kgCO2e/MWh)

36



TEGy = Total electricity produced by the project activity, including the electricity supplied to the grid and the electricity supplied to internal loads, in year y (MWh) (b) If the power density of the project activity (PD) is greater than 10 W/m2: PE HP,y = 0 The power density of the project activity (PD) is calculated as follows:

PD = Power density of the project activity (W/m2) CapPJ = Installed capacity of the hydro power plant after the implementation of the project activity (W) CapBL = Installed capacity of the hydro power plant before the implementation of the project activity (W). For new hydro power plants, this value is zero APJ = Area of the reservoir measured in the surface of the water, after the implementation of the project activity, when the reservoir is full (m2) ABL = Area of the reservoir measured in the surface of the water, before the implementation of the project activity, when the reservoir is full (m2). For new reservoirs, this value is zero. According to the consolidated methodology AMS I.D. (Version 17), a reservoir is defined as a water body created in valleys to store water generally made by the construction of a dam. According to this definition, the project activity does not include a reservoir in its boundary. So, the project activity does not result in new reservoirs and it does not result in the increase of existing reservoirs. Hence it is concluded that; PE HP,y = 0 Consequently; PE FF,y ,+PE GP,y + PE HP,y = 0; Therefore; PEy = 0 ; The project emissions assessment concludes that the project emissions are zero.

37



2) Baseline Emissions 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 to be calculated as follows:

Where: BEy = Baseline emissions in year y (tCO2/yr) EGPJ,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,y = Combined margin CO2 emission factor for grid connected power generation in year y calculated using the latest version of the .Tool to calculate the emission factor for an electricity system. (tCO2/MWh) Calculation of EG PJ,y The calculation of EG PJ,y is different for (a) greenfield plants, (b) retrofits and replacements, and (c) capacity additions. The project activity is not the retrofit or replacement of an existing grid-connected renewable power plant, the project activity is not a capacity addition to an existing renewable energy power plant. Therefore options b) and c) are excluded. The project is a green field plant; the project activity is the installation of a new grid-connected renewable power plant/unit at a site where no renewable power plant was operated prior to the implementation of the project activity, Therefore EG PJ, is calculated as follows;

Where: EGPJ,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) EGfacility,y = Quantity of net electricity generation supplied by the project plant/unit to the grid in year y (MWh/yr)

38



EG PJ,y = 46,890 MWh/year61 Calculation of EF grid,CM,y The following procedures are undertaken according to the “Tool to calculate the emission factor for an electricity system” version 02. The following 7 steps will be applied; STEP 1. Identify the relevant electricity systems. STEP 2. Choose whether to include off-grid power plants in the project electricity system (optional). STEP 3. Select a method to determine the operating margin (OM). STEP 4. Calculate the operating margin emission factor according to the selected method. STEP 5. Identify the group of power units to be included in the build margin (BM). STEP 6. Calculate the build margin emission factor. STEP 7. Calculate the combined margin (CM) emissions factor. Step 1: Identify the relevant electricity systems According to the ”Tool to calculate the emission factor for an electricity system”, (Version 02) project electricity system is defined by the spatial extent of the power plants that are physically connected through transmission and distribution lines to the project activity and that can be dispatched without significant transmission constraints. Connected electricity system, 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. According to the “Tool to calculate the emission factor for an electricity system”, if the DNA of the host country has published a delineation of the project electricity system and connected electricity systems, these delineations should be used. If this information is not available, project participants should define the project electricity system and any connected electricity system, and justify and document their assumptions in the CDM-PDD. The following criteria can be used to determine the existence of significant transmission constraints: • In case of electricity systems with spot markets for electricity: There are differences in electricity prices (without transmission and distribution costs) of more than 5 per cent between the systems during 60 per cent or more of the hours of the year;

61

FSR

39



• The transmission line is operated at 90% or more of its rated capacity during 90% per cent or more of the hours of the year. Turkey does not have a DNA established yet therefore a published delineation of the project electricity system and connected electricity systems cannot be found. Therefore the project electricity system is defined for the Project activity as the Project site and all power plants attached to the National Grid, which is operated by TEİAŞ. There is no spot market for electricity in Turkey therefore this criterion can’t be used to determine the existence of significant transmission constraints. As seen from Figure 6, the transmission line is operated below 90% of its rated capacity therefore the project electricity system can be dispatched without significant transmission constraints. Turkey is connected to the national grids’ of neighbouring countries. These neighbour countries’ grids are the connected electricity system for the project activity. Import and export of electricity between these countries take place, according to the “Tool to calculate the emission factor for an electricity system” (version 02), emission factor for imports from neighbouring countries is considered zero tons CO2e/MWh for determining the OM. There is no information about interconnected transmission capacity investments. FIGURE 7: The Turkish National Grid62

62

http://www.geni.org/globalenergy/library/national_energy_grid/turkey/turkishnationalelectricitygrid.shtml

40



TABLE 11: Turkish Transmission Line Capacity63 Years Transmission Capacity (MVA) Peak Load (MW) Peak Load /Capacity

2007 82056.0 29215.0 35.6%

2008 89476.0 30532.0 34.1%

STEP 2: Choose whether to include off-grid power plants in the project electricity system (optional) 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. Option I is selected because there is no available data on off-grid power plants in Turkey. STEP 3: Select a method to determine the operating margin (OM): The baseline methodology allows a choice among four methods for the calculation of OM emission factor; a) b) c) d)

Simple OM, or Simple adjusted OM, or Dispatch data analysis OM, or Average OM

There exist no publicly available data for the dispatch data analysis (c) or for the simple adjusted OM (b). The simple OM emission factor can be calculated using either of the below given two options;  

Ex-ante option where a three year generation-weighted average based on the most recent data is used. Monitoring and recalculation of the emission factor is not required, or Ex-post option, where the data of the year is used, in which the project activity displaces grid electricity. Yearly update of the emission factor is required.

The Ex-ante option is selected to carry out the baseline methodology for the Project. The 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) in the "Tool to calculate the emission factor for an electricity system" version 02, is selected. The Option B of the Simple OM can be used, because; a) The necessary data for Option A is not available, b) Only renewable sources are considered as low cost/must run sources. The quantity of electricity supplied to the grid by these sources is known. c) Off-grid power plants are not included in the calculation.

63

Source: Transmission Capacity: www.teias.gov.tr/istatistik2008/53.xls

Peak Load: www.teias.gov.tr/istatistik2008/20(2006-2008).xls

41



As explained above, the ex-ante combined margin method will be used. There exists no nuclear power plant in Turkey, and there is no indication that coal or lignite is obviously used as must-run. Low-cost/must-run resources are defined as power plants with low marginal generation costs or power plants that are dispatched independently of the daily or seasonal load of the grid. They typically include hydro, geothermal,wind, lowcost biomass, nuclear and solar generation as indicated in the”Tool to calculate the emission factor for an electricity system” Version 02.1.0. As particularly for Turkey, the coal and lignite fired electricity generation constitutes 28.3% of the national power production profile.64 Due to the fact of operating such facilities are fully dependant on coal cost, relatively, the hydro geothermal and wind activities don’t have such cost since their fuel is renewable resources. Therefore coal-fired plants can’t be determined as low cost compared to the renewable alternatives. At a period of nationwide excess electricity supply and/or lower load demand period, the coal fired powerplants will be asked o undertake their functioning so as to maximize the utilization of hydro, thermal and wind activities that will consume renewable resources with no cost of raw material to generate power. Therefore in Turkey, coal and lignite-fired electricity production doesn’t belong to ‘must run’ category compared to the alternatives above. To calculate the emission factor of Turkey ‘Simple OM’ is used on the grounds that low cost/must run resources in Turkish National Grid constitute less than 50% of the grid resource mix, excluding the coal lignite-fired power plants for the reasons that are above. Hydro, geothermal, wind power plants and other renewable are included as low- cost/must- run resources, which turns out to be 19.33% of the total electricity generation on average between the years 2007 and 2009. Since the share of low-cost/must-run resources are less than 50% on average of the 5 most recent years and as the available data are limited, the simple OM method will be implemented. It can be seen from the table below that the share of generation by low-cost/must-run resources is under 50%. Available statistics for the most recent years have been used. TABLE 12: Electricity Generation Breakdown of the Turkish Grid for the Last 3 Years65

THERMAL (GWh) LOW COST/MUST RUN (GWh) TOTAL (GWh) LOW COST/MUST RUN PROPORTION ( %)

64

Please refer to Figure 5.

65

www.teias.gov.tr/istatistik2007/31(40-07).xl

2007

2008

155,196.2

164,139.3 34,278,7

36,361.9

2009 156.923.4 37.889.5 194.812.9

191,558.1

198,418.0

19

20

42

19



STEP 4. Calculate the operating margin emission factor according to the selected method: According to the methodology, the simple OM emission factor (EFOM Simple, y) is calculated as 2006-2008 generation-weighted average emissions per electricity unit (tCO2/MWh) of all generating sources serving the system excluding low-operating cost and must-run power plants. The formula of EFOM Simple, y calculation is; EFgrid, OM simple, y = ∑FCi,y × NCVi,y × EFco2,i,y ∕ ∑EGy

(3)

Where; EFgrid,OMsimple,y = Simple operating margin CO2 emission factor in year y (tCO2/MWh) FCi,y volume unit)

= Amount of fossil fuel type i consumed in the project electricity in year y (mass or

NCVi,y unit)

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

EFCO2,i,y

= CO2 emission factor of fossil fuel type i in year y (tCO2/GJ)

EGm,y (MWh)

= Net electricity generated and delivered to the grid by power plant / unit m in year y

i year y

= All fossil fuel types combusted in power sources in the project electricity system m in

y = Either three most recent years for which data is available at the time of submission of the GS-PDD to the DOE for validation (ex-ante option) or the applicable year during monitoring (ex-post option). Data about the fuel consumption for electricity generation, electricity generation by fuel type, import and export were obtained from the Turkish Electricity Distribution Company (TEİAŞ) web site. Operating and Build Margin calculations have been based on the data for 2006-2008. Details of the data used for the calculations are given in Annex 3. Using the available data and ACM0002 methodology, the tables of information required for the calculations are as follows:

43



TABLE 13: Fuel Generation Sources Connected to the Grid (2006-2008)66 units: tons for solid fuels 1000m3 for gaseous fuels 2007 2008 2009 Total

Fci,y Hard Coal + Imported Coal Lignite Fuel Oil Diesel Oil LPG Naphtha Natural Gas

6029143

6270008

6621177

18920328

61223821 2250686 50233 0 11441 20457793

66374120 2173371 131206 0 10606 21607635

63620518 1594321 180857 111 8077 20978040

191218459 6018378 362296 111 30124 63043468

NCV1 (TJ/tons), for gaseous fuels; (TJ/1000m 3 ) EF CO2,l (tCO2 /TJ) 2008

2009

2007

Hard Coal + Imported Coal

0,02160

0,02160

0,02160

94,6

Lignite

0,00550

0,00550

0,00550

90,9

Fuel Oil

0,03980

0,03980

0,03980

75,5

Diesel Oil

0,04140

0,04140

0,04140

72,6

LPG

0,04480

0,04480

0,04480

61,6

Naphta

0,04180

0,04180

0,04180

69,3

Natural Gas

0,04650

0,04650

0,04650

54,3

TABLE 14 : Relation Between Net and Gross Electricity Generation67 EGy (GWh)

2008 2009 2007 Total Net Thermal Gen.

66 67

Gross Generation

Net Generation

Net/Gross

198418 194812.9 191558.1

189761.9 186619.3 183339.7

0.95637 0.95794 0.95710

Gross Generated Thermal 164139.3 156923.4 155196.2

Net Generated Thermal

Import

Total

156978.6281 150323.3875 148537.8313

789.4 812 864.3

157768 151135.4 149402.1

455839.847

2465.7

458305.5

www.teias.gov.tr/ist2008/43.xls and www.teias.gov.tr/ist2008/44.xls www.teias.gov.tr/ist2007/30(84-07).xls and www.teias.gov.tr/istatistik2008/32(75-08).xls

44



As calculated by equation 3, using values from tables 13 to 15, EFgrid, OM simple,, y = 312,703,437.6 (tCO2) / 458,305,547 (MWh) = 0,682 (tCO2/MWh) STEP 5. Identify the cohort of power units to be included in the build margin: In this step, a generation-weighted average emission factor is calculated based on a sample of power plants, which have been taken into operation recently. The sample group of power plants m used to calculate the build margin consists of either: a) The set of 5 power units that have been build most recently. b) The set of power capacity additions in the electricity system that comprise 20% of the system generation (in MWh) and that have been build most recently. For conducting the calculations option (b) is selected, because this option results in a larger electricity generation. The "Tool to calculate the emission factor for an electricity system" requires the sample list of recent capacity additions to constitute at least 20% of the system generation. This requirement is met as shown in the table below; TABLE 15: Generation of Recent Capacity Additions68 Generation of the Sample List 2009 Generation, GWh UNFCCC Threshold, % of Generation UNFCCC Threshold, GWh Capacity Additions, 2003-2006 GWh

Generation (GWh) 194,812.9 20% 38,962.58 41,053.83

In terms of vintage data, there are two available 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 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, expost, including those units built up to the year of registration of the project activity, or, if information up 68

www.teias.gov.tr/ist2006/8.xls ww.teias.gov.tr/istatistik2005/7.xls www.teias.gov.tr/istat2004/7.xls www.teias.gov.tr/istatistik/7.xls www.teias.gov.tr/istat2002/7.xls www.teias.gov.tr/istatistikler/7.xls

45



to the year of registration is not yet available, including those units built up to the latest year for which information is available. For the second crediting period, the build margin emission factor shall be calculated ex-ante, as described in option 1 above. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. Option 1 is selected. The data of the most recent commissioned power plants are being published by Turkish Electricity Transmission Company (TEİAŞ) on annual basis. For build margin calculations, the power plants taken into operation between the years of 2004 and 2008 are included in the cohort of power units. Performance revisions, modifications, retrofits and dismantling of power plants have been excluded from the samples list for the build margin calculations. Power plants that have been taken into operation in 2009 are not included as the data is unavailable of insufficient. Based on these requirements and conditions, the final list of selected power plants is summarized in the Baseline Information in Annex 3. As can be seen from the tables on Annex 3, the Iskenderun GR I-II plant is included fully in the calculation since the part of its capacity falls in 20% of 2009 electricity generation. Therefore in Table 17, the capacity additions included in the calculation is higher than the 20% threshold. STEP 6. Calculate the Build Margin Emission Factor: The build margin 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 available, calculated as follows; EFgrid, BM, y = ƩEGm, y x EFEL, m, y / ƩmEGm, y

(4)

Where: EF grid,BMsimple,y = Build margin CO2 emissions factor in year ‘y’ (tCO2/GWh) EGm,y = Net quantity of electricity generated and delivered to the grid by power unit m in year y (GWh) EF EL,m,y = CO2 emission factor In accordance with the Emission Factor Tool, the CO2 emission factor of each power unit m (EF EL,m,y) should be determined by the guidance in step 3a) for the simple OM. Using options A1, A2 and 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 where: And the EFEL, m, y is found as; EFEL, m, y = EFCO2, m, i, y x 3.6 / ηm, y

(5)

EF EL,m,y = CO2 emission factor of the power unit in year ‘y’ (tCO2/MWh) EF CO2m,i,y = Average CO2 emission factor of fuel type ‘i’ used in power unit ‘m’ in year ‘y’ (tCO2/GJ)

46



ηm,y = Average net energy conversion efficiency of power unit ‘m’ in year ‘y’(%)

Using the data given in tables 16 and 17 the Build Margin emission factor is calculated as follows;

TABLE 16: Net quantity of electricity generated and delivered to the grid by power unit ‘m’

EGm,y (MWh) Fuel Type

2006

2003

2004

2005

Hard Coal

0

9315000

337500

1125000

10777500

Lignite

7020000

0

0

4420000

11440000

Fuel Oil

0

0

466200

99100

Natural Gas

0

692300

8834170

7117700

Diesel Oil

0

0

4100

0

Total Renawable

0

347800

241760

1033200

Total

Total

565300 16644170 4100 1622760 41.053.830,00

TABLE 17: Emission Factor of the Power Units6970 EFCO2 (tCO2/TJ)

η

EFEL (tCO2/MWh)

Hard Coal

94,6

0,34

1,014

Lignite

90,9

0,33

0,998

Fuel oil

75,5

0,35

0,774

Natural Gas

54,3

0,46

0,425

Diesel Oil

72,6

0,28

0,950

2001

EF grid,BMsimple,y =

29,851949.11 (tCO2) / 41,053,830 (MWh)

EFgrid, BMsimple,y = 0.727 (tCO2/MWh)

69

http://www.cedgm.gov.tr/dosya/cevreatlasi/atlasin_metni.pdf

70

The lower limits of the 95% confidence interval stated in the "2006 IPCC Guidelines for National Greenhouse Gas Inventories"

47



STEP 7. Calculate the Combined Margin Emission Factor The Operating Margin refers to a cohort of power plants that reflect the existing power plants whose electricity generation would be effected by the proposed Project activity. The Build Margin refers to a cohort of power plants that reflect the type of power units whose construction would be effected by the proposed Project activity. The Combined emission factor EFgrid,CM,y for the Project activity is calculated as a weighted average of the Operating Margin emission factor and Build Margin emission factor as described in the baseline methodology;

EFgrid,CM,y = WOM x EF + WBM x EFgrid,BM,y Where: EF grid,BM,y

= Build margin CO2 emission factor in year ‘y’ (tCO2/MWh)

EF grid,OM,y

= Operating margin emission factor in year ‘y’ (tCO2/GWh)

wOM

= Weighting of operating margins emissions factor (%)

wBM

= Weighting of build margin emission factor (%)

(6)

(wom and wbm are the default values stated in the Emission Factor Tool and are both 0.5 for the first crediting period)

Using equation 6 and the values calculated above the combined margin emission factor is: EF grid,CM,y = EF grid,OM,y x wOM + EFgrid,BM,y x wBM

(7)

EF grid,CM,y = (0.682x0.5)+( 0.727 x 0.5) = 0.341 + 0.3635 EF grid,CM,y =

0.7045 (tCO2/MWh)

For the sake of being conservative, the emission factor is rounded down to 0.704 (tCO2/MWh). 3) Project Leakage . Fossil Fuel Combustion (PEFF,y) PE FF,y = Project emissions from fossil fuel consumption in year y (tCO2/yr) is calculated according to the UNFCCC tool “Tool to calculate project or leakage CO2 emissions from fossil fuel combustion” (Version 02)”

Where:

48



PE Fc,j,y = Are the CO2 emissions from fossil fuel combustion in process j during the year y (tCO2/yr); FC i,j,y = Is the quantity of fuel type i combusted in process j during the year y (mass or volume unit/yr); COEF i,y = Is the CO2 emission coefficient of fuel type i in year y (tCO2/mass or volume unit) i = Are the fuel types combusted in process j during the year y Since the project activity is a hydro electrical power plant there is no use of any fuel type. Therefore FC i,j,y = 0. Hence Project emissions from fossil fuel consumption in year y for all years of the project activity is zero; PE FF,y = 0 Emissions of non-condensable gases from the operation of geothermal power plants (PEGP,y) PE GP,y is calculated as follows: PE GP,y = ( W steam,CO 2,y + W steam,CH 4,y * GWP CH 4 ) * M steam,y Where: PEGP,y = Project emissions from the operation of geothermal power plants due to the release of non-condensable gases in year y (tCO2e/yr) wsteam,CO2,y = Average mass fraction of carbon dioxide in the produced steam in year y (tCO2/t steam) wsteam,CH4,y = Average mass fraction of methane in the produced steam in year y (tCH4/t steam) GWP CH4 = Global warming potential of methane valid for the relevant commitment period (tCO2e/tCH4) Msteam,y = Quantity of steam produced in year y (t steam/yr)

The project activity does not involve any Geothermal components hence; PE GP,y = 0

49



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

Data / Parameter: Data unit: Description: Source of data used:

Value applied: Justification of the choice of data or description of measurement methods and procedures actually applied : Any comment:

Data / Parameter: Data unit: Description: Source of data used: Value applied: Justification of the choice of data or description of measurement methods and procedures actually applied : Any comment:

71

EFCO2,i,y tCO2/TJ CO2 emission factor of fossil fuel type i in year y. IPCC default values at the lower limit of the uncertainty at a 95% confidence interval as provided in table 1.4 of Chapter1 of Vol. 2 (Energy) of the 2006 IPCC Guidelines on National GHG Inventories71 See Table 15. Data used for OM and BM calculations.

EGfacility,y MWh Net electricity delivered to the grid by Saray HEPP project in year “y”. Electricity generation reports submitted by the project owner. 46,890 Data used for OM and BM calculations.

-

“Tool to calculate the emission factor for an electricity system” (Version 02.1.0)

50



Data / Parameter: Data unit: Description: Source of data used: Value applied: Justification of the choice of data or description of measurement methods and procedures actually applied : Any comment: Data / Parameter: Data unit: Description: Source of data used: Value applied: Justification of the choice of data or description of measurement methods and procedures actually applied : Any comment:


EGy GWh Net electricity generated by power plants in Turkey in years 2007, 2008 and 2009. TEIAS web site: www.teias.gov.tr See Table 12. Data used for emission reduction calculation.

FCi,y tCO2/TJ Tons or 1000 m3 for gasses. Amount of fuels consumed by thermal power plants for electricity generation in terms of fossil fuel type “i” in year “y”. TEIAS website. See Table 10. Data used for OM calculation.

-

NCV TJ/kt Net calorific values of fuel combusted in power plants. TEIAS web site. See Table 11. Data used for OM and BM calculations.

-

51




η

Data / Parameter: Data unit: Description:

EFgrid,CM,y tCO2/MWh Combined margin CO2 emission factor for grid connected power generation in year y calculated using the latest version of the ‘Tool to calculate the emission factor for an electricity system’ As per the ‘Tool to calculate the emission factor for an electricity system’, the data flow will be conducted with the project activity and Turkish Electricity Transmission Company (TEİAS) is the relevant source to obtain statistical information for the necessary calculations. 0.704 Calculations are made ex-ante, therefore no measurement is made. Data is only taken from TEIAS and IPCC 2006

Source of data used:

Value applied: Justification of the choice of data or description of measurement methods and procedures actually applied : Any comment:

B.6.3

Average net energy conversion efficiency of power unit m or k in year y www.cedgm.gov.tr See Table 18. Data used for OM calculation.

-

-

Ex-ante calculation of emission reductions:

Baseline emission According to the formula 7 in section B.6.1., the results of EFgrid,OM,y , EFgrid,BM,y and EFgrid,CM,y are listed in following Table 18, the detailed calculation is shown in Annex 3.

52



TABLE 18: Calculating result of baseline emission factor of Turkish National Grid EFgrid,OM,y (tCO2e/MWh) 0.682

EFgrid,BM,y (tCO2e/MWh) 0.727

EFgrid,CM,y (tCO2e/MWh) 0.704

According to the formula in Section B.6.1., the baseline emissions (BEy) of the project in a typical year are calculated as follows: BEy= EGBL,y﹒EFCO2= 0.704 tCO2e /MWh×46,890 MWh = 33,010.5 tCO2 e /yr Project emission According to B.6.1., PEy = 0 Leakage According to Section B.6.1., LEy = 0 Emission Reductions According to the formula in Section B.6.1., the emission reductions (ERy) of the project in a typical year are calculated as follows: ERy (tCO2e/yr) = BEy －PEy－LEy = 33,010.5－ 0－ 0 = 33,010.5 tCO2e

B.6.4

Summary of the ex-ante estimation of emission reductions: TABLE 19: Summary of Baseline Calculations

Parameter EFgrid,OM,y EFgrid,BM,y EFgrid,CM,y EGfacility,y ERy

Definition Operating Margin Emission Factor in year y. Build margin Emission Factor in tear y. Combined Margin Emission Factor in year y. Net Electricity Delivered to the Grid by Saray HEPP Project. Emission Reductions in year y.

53

Value 0.682 (tCO2/MWh) 0.727 (tCO2/MWh) 0.704 (tCO2/MWh) 46,890 (MWh) 33,010.5 tCO2e



TABLE 17: Ex-ante estimation of emission reductions

Years

2014 2015 2016 2017 2018 2019 2020 Total

Estimated baseline emissions or removals (tCO2e)

Estimated project emissions or removals (tCO2e)

33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 231.073.5

0 0 0 0 0 0 0 0

Estimated leakage emissions (tCO2e) 0 0 0 0 0 0 0 0

Estimated net GHG emission reductions or removals (tCO2e) 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 33,010.5 231.073.5

B.7

Application of a monitoring methodology and description of the monitoring plan:

B.7.1

Data and parameters monitored: B.7.1

Data and parameters monitored:

Data / Parameter: Data unit: Description: Source of data to be used: Measurement procedure (if any):

Monitoring frequency: QA/QC procedures to be applied: Any comment:

EGfacility,y kWh/y Quantity of net electricity supplied to the grid by Saray HEPP in year “y”. Project activity site. Meter reading. Invoices of electricity sales to the grid. Quantity of net electricity supplied to the grid by the project activity will be measured using cumulative electricity meters. Collected data will be archived monthly. Data will also be checked with invoices of electricity supplied to the grid. Continuous measurement and at least monthly recording. Turkish Electricity Transmission Company (TEİAŞ) is responsible of calibrating the electricity meters and of checking them monthly for accuracy. Cross check measurement results with records for sold electricity. -

54



Data / Parameter: Data unit: Description: Source of data to be used: Measurement procedures (if any): Monitoring frequency: QA/QC procedures to be applied: Any comment:

B.7.2

CAPPJ MW The installed capacity of the project activity after the implementation of the project. Project site. Determine the installed capacity based on recognized standards. Yearly. -

Description of the monitoring plan:

The project owner will implement the established monitoring protocol before the project gets operational. The objective of the monitoring protocol is to provide precise, non-simulated and conservative monitoring data of the emission reductions and ensure the laudability of carbon crediting of the project owner. Furthermore, convincing, assessable and long term global environmental benefits relating to the GHG emission reduction accumulated by the proposed project can be verified and certified. Data to be monitored  

Electricity delivered by the project to the national grid (EGfacility,y) The installed capacity of the project after implementation (CAPPJ)

The net electricity generation which is basis to sales is already measured and recorded by both PMUM database and the project owner since the implementation of the project. The plant manager and its appointed team of control room operators (whom will be informed about VER concepts and mechanisms and how to monitor and collect the data) will be responsible for gathering all relevant data and keeping the records. Since the emission factor is calculated as ex-ante and according to the Monitoring Methodology AMS I.D. (Version 16.6), the Combined Margin calculation provisions will be done according to the latest version of ‘Tool to calculate the emission factor for an electricity system’ by Borga Carbon Consultancy for each following renewable crediting period. The installed capacity after implementation (CAPPJ) and PLF rate will be monitored as well in order to verify the pre-operation projections. Since the emission factor is calculated as ex-ante and according to the Monitoring Methodology, the Combined Margin calculation provisions will be done according to the latest version of ‘Tool to calculate the emission factor for an electricity system’ by Borga Carbon Consultancy which is subject to verification annually.

55



FIGURE 8: The Monitoring Structure

The net electricity fed to the grid by the project activity will be monitored in accordance with the approved methodology. The electricity generated by the project activity will be measured by two (a main and a back-up) meters. The meters shall be in direct accord with the Declaration on Meters that are Used in the Electricity Market72 that is announced by Electricity Market Regulatory Authority and the minimum requirements that the electrical meters must satify which are stipulated by TEDAS73. The meters must be in compliance with International Electro Technical Commission74 standards and Turkish Standards Institution75 requirements. The meters shall be capable of measuring the active and reactive energy on buy and sell aspects as well as they shall be qualified for advanced measuring of the power quality and saving historical data. The meters will be locked and sealed preventing any external interference other than the distribution company officials. The electricity generation indexes will be read by the operators of the power plant on hourly basis, recorded on the ‘daily meter operation fact sheet’ and archived. The billing will be performed by the distribution company after the tenth day of the meter reading for electricity sales revenues. In case of a malfunction of a meter, the non-defected one’s readings are subject to determine the monthly index. In such cases, the person in charge from the distribution company will be notified and the sealed and locked meters will be opened in the presence of the representatives from the official distribution company in order to determine and record the breakdown and the reason. The official record

72

www.epdk.gov.tr/documents/10157/326b88e3-e36f-4d7c-af43-1f8b5959a203

73

www.tedas.gov.tr/attached/Duyurular/tedas-elktro-sayac.doc

74

www.iec.ch

75

www.tse.org.tr/

56



of the electricity generation and the breakdown report in case of a malfunction will be submitted to Borga Carbon Ltd., monthly76. Calibration of the Meters The meters will be factory calibrated and delivered to the customer with the calibration statement.The periodic calibration process of the meters are subject to The Directive on Metering and Meter Calibration Procedures that is published in the Official Gazette, number 22000, on the date of 24/07/1994 and executed under the authority of the Ministry of Industry and Trade77. The meters that are subject to billing are regulated under this protocol nationwide. In Article 9, it is clearly stated that it is mandatory to perform calibration on the electricity meters once in every ten years. The periodic duration starts as of the first calibration and the official sealing day of the devices. Article 6 regulates the periodic calibration applications. Every year, by the start of January till the end of February, the Ministry announces on the government television and radio, the addressed government offices for receiving the periodic calibration requests based on the perimeters and types of the meters. The distribution company who uses the meters at distribution is responsible for application and execution of the calibration control. Article 8 states that the periodic calibrations are performed by the Measurement and Regulation Organization of the Ministry and the appointed Municipal Measurement and Regulation Offices. The mandatory or voluntary calibration reports will be provided to Borga Carbon by the project owner and will be archived as planned in the Monitoring Plan. Monitoring the Flow Regime Under the regulations of Water Usage Rights Agreement78, the 4th Article states that the aspects of the hydro resources that are allocated to the private entities are planned by DSI (State Hydraulic Works) determining the water amount and time interval regarding the energy generation. The private entities are obliged to follow these plans and act accordingly. The flow amount in order to sustain the natural life of the downstream that is determined by the Project Introductory File79 and Environmental Impact Assessment80 approved by the Environment and Ministry should be released. According to the 14th Article, the DSI approved and controlled Stream Gagging Stations will be located on the upstream and downstream of the proposed project. Their locations will be determined by DSI. The hydrometric measurements and evaluations will be done by DSI and the project owner. The expenses of electronic stations shall be sponsored by the project owner. The maintenance and repairmen of the stations will be performed under DSI supervision. The plant can’t start commissioning unless fulfilling the requirements regarding these stations. The mandatory or voluntary calibration reports will be provided to Borga Carbon by the project owner and will be archived as planned in the Monitoring Plan. 76 77

Meter Reading Protocol sample is available upon request. http://osgm.sanayi.gov.tr/Files/Mevzuat/olcu-ve-olcu-aletleri-mua-22042010183044.pdf

78

Water Usage Rights Agreement contracted between the project owner and the Ministery of Energy and Natural Resources dated 08/07/2010. 79

Available upon request

80

Annex 6: EIA Exemption Report

57



Data collection The QA&QC procedures for recording, maintaining and archiving data shall be established and implemented as part of this VER project. On a fixed day of each month, the assigned worker of the facility will read the meters and record the read figures in the generation statement note which can be verified by the grid company as well. The project owner is responsible for monitoring of all the meters. The data will be recorded and collected daily, and archived in electronic form monthly. The installed capacity of the project will be indicated in the documentation of the supplier of the hydroturbines. The operational installed capacity data will be recorded and archived in electronic form. Maintenance records and any calibration documents will be retained by the project owner. The QA&QC procedures for recording, maintaining and archiving data shall be optimized to ensure the project which shall be able to provide credible, accurate, transparent and conservative monitoring data in order to calculate the emission reductions by the project activity. In case of a default or incoherent data, the dedicated manager, i.e. the plant manager, in charge of the data collecting and transferring, shall correct the data following the “data handling protocol” that will be written during the implementation of the project. In case of defaults not covered by the “data handling protocol”, the plant manager is responsible for validating or correcting the default data with a conservative approach and for writing a detailed report referring to TEIAS standards and grid connection agreements. Monitoring Report The monitoring report is prepared by Borga Carbon Ltd., and be submitted to the duly authorized and appointed Designated Operational Entity ‘DOE’ before each verification period. The report should cover the monitoring of grid-connected power generation, calculation reports of the emission reduction as well as maintenance and calibration reports. All written documentation such as maps, drawings, the Environmental Impact Assessment or EIA exemption report, should be well maintained and retained and should be available to the verifier upon request. Thus the creditability, reliability, transparency and traceability of the project records and calculation of emission reductions could be ensured. Record management All records generated by the projects should be managed according to the record management procedure. The monitoring data should be continuously recorded; the electronic documents and paper documents should also be collected. All the documents and records will be kept in a secure and retrievable manner for at least 2 years after the end of the project crediting period. All measurements should be conducted with calibrated and perfectly operating equipments according to relevant industry and TEIAS standards.

58



B.8 Date of completion of the application of the baseline and monitoring methodology and the name of the responsible person(s)/entity(ies) Date of completion: 03/03/2012 Name of person/entity: Borga Carbon Ltd. Ms. Alev Erol Tel: +90 212 356 96 76 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:

07/09/2011 – Electricity Generation License obtained for the project activity.

C.1.2. Expected operational lifetime of the project activity: 49 years and 0 months. 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:

First electricity generation projected as of 2014. C.2.1.2.

Length of the first crediting period:

7 years and 0 months.

59



C.2.2. Fixed crediting period: C.2.2.1.

Starting date:

C.2.2.2.

Length:

Not applicable.

Not applicable. SECTION D. Environmental impacts

D.1. If required by the host Party, documentation on the analysis of the environmental impacts of the project activity: Saray small scale HEPP project had obtained a written report from the Ministry of Environment and Forestry that the Environment Impact Assessment (EIA) is not required81.

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: Not applicable. SECTION E. Stakeholders’ comments

E.1.

Brief description how comments by local stakeholders have been invited and compiled:

In order to appraise the local community’s reviews and opinions on the proposed project, a stakeholders meeting was held in Karaca Tea Factory, Pinaralti Village on Tuesday, April 5th,2011at 14:30 in Trabzon province. Representatives from various non-governmental organizations, Ministry of Environment and Forestry, local government officials and the local community that rests within the sphere of influence of the project activity were invited via e-mail, phone calls, mailed invitations and local newspaper advertisements. 15 local people had attended to the meeting, and all of them wrote their names down in the participant list and 12 of them filled in the matrixes and 10 of them filled in the evaluation forms. Unfortunately, although specially encouraged, there were no female participants in the meeting, probably because of cultural and social dynamics in the region. When it was asked about the low attendance portion of villagers to the meeting, it has been observed that the Village Headman’s were particularly confident in their participation to the meeting indicating that the local community gives them full responsibility for their opinions and they will be informing the local community about the meeting context. Their comments were complied as sustainability matrix, evaluation forms and verbal comments during the meeting. 81

Annex 6: EIA Exemption Letter

60



E.2.

Summary of the comments received:

The participants were quite informed about the technology of the project and the process that will be followed before the project gets operational due to Incirli HEPP has been built in the previous two years in the same area by the same project owner. The participant village headmen have known Mr. Yasar Sekerci, the project coordinator, since back then and they had developed sincere relationships. The major concerns were basically about the blasts during the construction phase of the transmission tunnel that may cause cracks on the residential buildings near the project area and the tea plantations that the tunnel will be located underneath. Addressing and removing the concerns by referring to the technical aspects of the project activity, eventually it was observed that the participants were satisfied and encouraging the implementation of the project activity and development of it under Gold Standard regulations. E.3.

Report on how due account was taken of any comments received:

The local residents and authorities are supportive of the proposed project. Therefore, there is no need to modify the project due to the comments received during the investigation. The project owner is responsible to compensate any unexpected damage or harm that will be caused by the project activity.

61



Annex 1 CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY Organization: Street/P.O.Box: Building: City: State/Region: Postcode/ZIP: Country: Telephone: FAX: E-Mail: URL: Represented by: Title: Salutation: Last name: Middle name: First name: Department: Mobile: Direct FAX: Direct tel: Personal e-mail:

MERTLER Enerji Uretim Pazarlama A.S. Cetin Emec Bulvari No: 60/7 Balgat, Cankaya - ANKARA

TURKEY +90 212 350 05 00

Mr. Hasan Adali Vice President Adali Hasan

[email protected]

62



Organization: Street/P.O.Box: Building: City: State/Region: Postcode/ZIP: Country: Telephone: FAX: E-Mail: URL: Represented by: Title: Salutation: Last name: Middle name: First name: Department: Mobile: Direct FAX: Direct tel: Personal e-mail:

Borga Carbon Ltd. Fulya Mah. Ortaklar Cad. Kemal Bey Apt. No 24/4 Mecidiyekoy - Istanbul

TURKEY +90 212 356 96 76

Ms. Alev Erol Project Manager Erol Alev 0090 535 727 96 97

[email protected]

63



Annex 2 INFORMATION REGARDING PUBLIC FUNDING

64



ANNEX 3 BASELINE INFORMATION Turkish Energy Generation Map82

82

http://www.euas.gov.tr/_Euas/Images/Birimler/basin/euasharitafinal.jpg

65



TÜRKİYE KURULU GÜCÜNÜN YILLAR İTİBARİYLE GELİŞİMİ ANNUAL DEVELOPMENT OF TURKEY'S INSTALLED CAPACITY (1913 - 2009) Birim(Unit) : MW YIL

TERMİK

HİDROLİK

TOPLAM

ARTIŞ

YIL

TERMİK

HİDROLİK

JEOTER.+RÜZ.

TOPLAM

ARTIŞ

YEAR

THERMAL

HYDRO

TOTAL

INCREASE

YEAR

THERMAL

HYDRO

GEOTHERM.WIND

TOTAL

INCREASE

% 1913 1923 1924 1925 1926 1927 1928 1929 1930 1931 1932 1933 1934 1935 1936 1937 1938 1939 1940 1941 1942 1943 1944 1945 1946 1947 1948 1949 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1961 1962 1963 1964 1965

17.2 32.7 32.8 33.3 48.4 51.5 64.4 68.9 74.8 98.7 99.8 104.3 112.9 121.2 133.3 161.7 173.1 210.1 209.2 213.8 218.5 228.2 233.7 237.7 238.5 242.3 296.2 371.8 389.9 399.2 412.0 470.1 480.2 573.5 731.9 777.6 809.1 843.4 860.5 878.6 901.2 902.6 921.1 985.4

0.1 0.1 0.1 0.1 0.2 0.4 1.5 3.2 3.2 3.2 3.5 3.5 4.5 5.0 5.2 5.4 5.4 5.5 7.8 8.2 8.2 8.2 8.2 8.2 9.0 9.1 9.3 10.0 17.9 24.0 25.8 29.4 36.7 38.1 154.2 161.8 220.9 317.6 411.9 445.3 469.6 478.5 497.2 505.1

17.3 32.8 32.9 33.4 48.6 51.9 65.9 72.1 78.0 101.9 103.3 107.8 117.4 126.2 138.5 167.1 178.5 215.6 217.0 222.0 226.7 236.4 241.9 245.9 247.5 251.4 305.5 381.8 407.8 423.2 437.8 499.5 516.9 611.6 886.1 939.4 1030.0 1161.0 1272.4 1323.9 1370.8 1381.1 1418.3 1490.5

%

-

Not:Jeotermal santralının kurulu gücü 2003 yılında EÜAŞ tarafından revize edilerek 15 MW'a düşürülmüştür.

89.6 0.3 1.5 45.5 6.8 27.0 9.4 8.2 30.6 1.4 4.4 8.9 7.5 9.7 20.6 6.8 20.8 0.6 2.3 2.1 4.3 2.3 1.7 0.7 1.6 21.5 25.0 6.8 3.8 3.4 14.1 3.5 18.3 44.9 6.0 9.6 12.7 9.6 4.0 3.5 0.8 2.7 5.1

1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

1028.0 1257.4 1243.4 1243.4 1509.5 1706.3 1818.7 2207.1 2282.9 2407.0 2491.6 2854.6 2987.9 2987.9 2987.9 3181.3 3556.3 3695.8 4569.3 5229.3 6220.2 7474.3 8284.8 9193.4 9535.8 10077.8 10319.9 10638.4 10977.7 11074.0 11297.1 11771.8 13021.3 15555.9 16052.5 16623.1 19568.5 22974.4 24144.7 25902.3 27420.2 27271.6 27595.0 29339.1

616.3 701.7 723.2 723.8 725.4 871.6 892.6 985.4 1449.2 1779.6 1872.6 1872.6 1880.8 2130.8 2130.8 2356.3 3082.3 3239.3 3874.8 3874.8 3877.5 5003.3 6218.3 6597.3 6764.3 7113.8 8378.7 9681.7 9864.6 9862.8 9934.8 10102.6 10306.5 10537.2 11175.2 11672.9 12240.9 12578.7 12645.4 12906.1 13062.7 13394.9 13828.7 14553.3

17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 26.2 26.2 36.4 36.4 36.4 33.9 33.9 35.1 81.9 169.2 393.5 868.8

1644.3 1959.1 1966.6 1967.2 2234.9 2577.9 2711.3 3192.5 3732.1 4186.6 4364.2 4727.2 4868.7 5118.7 5118.7 5537.6 6638.6 6935.1 8461.6 9121.6 10115.2 12495.1 14520.6 15808.2 16317.6 17209.1 18716.1 20337.6 20859.8 20954.3 21249.4 21891.9 23354.0 26119.3 27264.1 28332.4 31845.8 35587.0 36824.0 38843.5 40564.8 40835.7 41817.2 44761.2

Note: Installed capacity of Geothermal P.P. Is revised and decreased to 15 MW in 2003 by EÜAŞ. reflected to all installed capacity table as well.

66

10.3 19.1 0.4 0.03 13.6 15.3 5.2 17.7 16.9 12.2 4.2 8.3 3.0 5.1 0.0 8.2 19.9 4.5 22.0 7.8 10.9 23.5 16.2 8.9 3.2 5.5 8.8 8.7 2.6 0.5 1.4 3.0 6.7 11.8 4.4 3.9 12.4 11.7 3.5 5.5 4.4 0.7 2.4 7.0



67



68



69



70



71



Annex 4 MONITORING INFORMATION Data which is subject to Monitoring

Electricity Generation Responsible Record Type Record Management

Net electricity supplied to the grid

(EGfacility, y) Appointed Staff of the Facility for Data Collecting and Plant Manager. Electronic The monitored data will be transferred monthly to the project owner and Borga Carbon Ltd. under the responsibility of the plant manager as well as meter maintenance and calibration conditions. They will be reviewed, assessed and archived by Borga Carbon Ltd. for the purpose of the verification procedure.

72



Annex 5 ELECTRICITY GENERATION LICENSE

73



Annex 6 ENVIRONMENTAL IMPACT ASSESSMENT REPORT

74

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