SARIGÜZEL DAM AND HYDROELECTRIC POWER PLANTS PD_SariguzelHES... · 2012-08-03 · SARIGÜZEL DAM...

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SARIGÜZEL DAM AND HYDROELECTRIC POWER PLANTS

Document Prepared By Enerjisa Group

Project Title Sarıgüzel Dam and Hydroelectric Power Plants

Version Version4

Date of Issue 18.01.2012

Prepared By Zeynep Pınar Öztürk

Contact Enerjisa Group, Sabanci Center Kule 2, 33340 4. Levent, ISTANBUL-Turkey,

Tel: +902123858842,

email: [email protected],

http://www.enerjisa.com.tr


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Table of Contents

1. Project Details .................................................................................................................................. 4 1.1 Summary Description of the Project ..................................................................................... 4 1.2 Sectoral Scope and Project Type ........................................................................................... 6 1.3 Project Proponent .................................................................................................................. 6 1.4 Other Entities Involved in the Project ................................................................................... 6 1.5 Project Start Date................................................................................................................... 6 1.6 Project Crediting Period ........................................................................................................ 6 1.7 Project Scale and Estimated GHG Emission Reductions or Removals ................................ 7 1.8 Description of the Project Activity ........................................................................................ 7 1.9 Project Location .................................................................................................................... 9 1.10 Conditions Prior to Project Initiation ............................................................................... 12 1.11 Compliance with Laws, Statutes and Other Regulatory Frameworks ............................. 12 1.12 Ownership and Other Programs ....................................................................................... 13

1.12.1 Proof of Title ................................................................................................................ 13 1.12.2 Emissions Trading Programs and Other Binding Limits ............................................. 13 1.12.3 Participation under Other GHG Programs ................................................................... 13 1.12.4 Other Forms of Environmental Credit ......................................................................... 13 1.12.5 Projects Rejected by Other GHG Programs ................................................................. 13

1.13 Additional Information Relevant to the Project ............................................................... 13 2 Application of Methodology ...................................................................................................... 14

2.1 Title and Reference of Methodology................................................................................... 14 2.2 Applicability of Methodology ............................................................................................. 14 2.3 Project Boundary ................................................................................................................. 15 2.4 Baseline Scenario ................................................................................................................ 16 2.5 Additionality ........................................................................................................................ 17 2.6 Methodology Deviations ..................................................................................................... 26

3 QUANTIFICATION OF GHG EMISSION REDUCTIONS AND REMOVALS ................... 26 3.1 Baseline Emissions .............................................................................................................. 26 3.2 Project Emissions ................................................................................................................ 33 3.3 Leakage ............................................................................................................................... 34 3.4 Summary of GHG Emission Reductions and Removals ..................................................... 34

4 Monitoring ................................................................................................................................. 38 4.1 Data and Parameters Available at Validation ...................................................................... 38 4.2 Data and Parameters Monitored .......................................................................................... 41 4.3 Description of the Monitoring Plan ..................................................................................... 41

5 Environmental Impact ................................................................................................................ 43 6 Stakeholder Comments .............................................................................................................. 45

Annex.1. Baseline Information ...................................................................................................... 47 Annex.2. Affirmative EIA decision ............................................................................................... 49 Annex.3. Single Line Diagram ...................................................................................................... 51 Annex.4. Hydropower Plants, Private Sector (2009) .................................................................... 52 Annex.5. Organizational Chart ...................................................................................................... 54


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Abbreviations BO: Built and Operate

BOT: Built, Operate and Transfer

HEPP: Hydroelectric Power Plant

EIA: Environmental Impact Assessment

EMRA (EPDK): Electricity Market Regulation Authority

EUAS: State Electricity Generation Corporation

MoEF: Ministry of Environment and Forestry

SCADA: Supervisory Control and Data Acquisition System

TEIAS: Turkish Electricity Transmission Company

TOR:Transfer of Operational Right TSKB: Turkish Industrial Development Bank

TKB: Turkish Development Bank


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1. PROJECT DETAILS

1.1 Summary Description of the Project

Sarıgüzel Dam and Hydroelectric Power Plants (HEPPs) are located in Kahramanmaraş Province, Ilıca Town on Ceyhan River. The project will be used only for energy generation purpose and has an Energy Generation License for 49 years obtained from Electricity Market Regulation Authority (EMRA) in 09/03/2006. The projects will be implemented under Kandil project group which also includes Dagdelen Weir and HEPP, Kandil Dam and HEPP, Hacınınoğlu Weir and HEPP. The project group was developed by General Directorate of State Hydraulic Works in 1966, including Kandil Dam and two other power plants developed downstream with a gross head of 507.70 meters. However, the master plan has been revised and locations, elevations and installed capacities of all projects have changed in March 2004. The feasibility report was updated in November 2007 and the construction of the projects has begun. During the optimization of energy generation without increasing the head of Kandil Dam and HEPP project, tail water level has been raised to 868.0 m from 860.0 m during 2010. This also dropped the operational water level of Sarıgüzel Dam and HEPPs and therefore the installed capacity from 100 MW to 95.4 MW as well. The design of the group of hydropower plants were finalized on November 2010 with a revised feasibility study. The project design has been reviewed and finalized with minor technical changes in June 2011. There are two hydroelectric power plants in the proposed project:

• Sarıgüzel Hydroelectric Power Plant (Sarıgüzel HEPP) • Sarıgüzel-1 Hydroelectric Power Plant (Sarıgüzel HEPP-1)

Within Sarıgüzel HEPP, a dam body, upstream cofferdam, spillway, derivation conduit, energy tunnel, surge chamber, penstock, powerhouse, service roads and a transmission line will be constructed. The water stored in the dam will be fed to the power house via 5,457.23 m length energy tunnel. The derivation conduit will be built as two sections, one of them providing 5.40 m3/sec water flow required for the aquatic life downstream. That water flow will be carried to Sarıgüzel 1 HEPP via penstock for electricity generation before released to water body. The installed capacity for Sarıgüzel HEPP will be 98.88 MWe which will be provided by two vertical axis francis turbines each having a capacity of 49.44 MWe. The average annual energy generation is estimated to be 281.191GWh. The net head is 109.11m and the project flow rate is 101 m3/sec. The surface area and volume of the dam reservoir will be 1.889 km2 and 47.45 hm3, respectively. Sarıgüzel-1 HEPP will have an installed capacity of 3.66 MWe and an average annual electricity generation of 30.572 GWh. The net head is 74.73 m and 5.40 m3/sec. There will be one horizontal axis francis turbine in the power plant. Power to be generated by Sarıgüzel HEPP will be transferred to Kandil Dam and HEPP upstream and Hacınınoğlu HEPP downstream. Two transmission lines will be built: (1) 154 kV, 12.50 km length, connected to Kandil HEPP switchyard, (2) 154 kV, 9.50 km length, connected to Hacınınoğlu HEPP switchyard. Sarıgüzel-1 HEPP will be connected to Sarıgüzel HEPP switchyard via 34.5kV line, 4.00 km length. The time schedule for the Projects is explained in Table.1. below:

Table.1. Time Schedule. Milestone Date Documentary Proof Generation licence acquired 09.03.2006 Generation license Feasibility study November 2007 Feasibility report Investment decision 16.04.2008 Board decision to sign EM

purchase agreement Electro-mechanical equipment purchased 28.04.2008 Purchase agreement Finance secured 13.06.2008 Loan agreement Affirmative EIA decision 08.01.2009 Affirmative EIA decision


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letter Construction started 15.06.2009 Notice to start construction Grid connection secured 02.07.2009 Grid connection agreement Feasibility revised November 2010 Feasibility report Estimated commissioning date 01.04.2013 - Start of crediting period 01.04.2013 - Verification frequency Once a year -

Sarıgüzel HEPP and Sarıgüzel-1 HEPP will generate 281,191 MWh and 30,572 MWh respectively on annual basis. This will replace the same amount of electricity generated by the grid and provide a reduction 185,811 tonnes of CO2eq. The Projects contribute to the sustainable development of the country by increasing generating electricity from renewable resources. The existing electricity grid system mostly relies on imported natural gas resources and that has been a financial burden for economical development of the country. The total hydropower capacity production of 35,958.4 GWh has been realized in 2009, which is only 18.46% of total electricity generation1. The project will utilize hydro power capacity for electricity generation and increase the share of renewable energy resources in electricity generation. It will also encourage other investors to construct hydro power generating units. Being a renewable energy project, the Projects will contribute to emission reductions and will replace the same amount of CO2 emissions which would have been caused by fossil fired power plants. The Projects will also create direct and indirect employment and intangible benefits in the region. Local unskilled workers will develop additional professional abilities, such as welding, plumbing, electrical and mechanical erection works etc. Those workers do not have any experience and will be trained. They will also get certificates as a pre-requisite for the construction workers and will be able to find job in that sector. Temporary jobs will be available for the local people living in the nearest village to the project site, namely Sarıgüzel, Hacınınoğlu and Kertmen villages. Approximately 200 workers will be hired during construction phase and 5-10 employees will be working permanently in the power plant. The materials have been purchased from local market providing an income for the community and enlivening the local economy as well. In addition to those benefits, access roads will be remedied which will ease the transportation in the region. Approximately 21 kms of the road will be renewed during the construction phase. A total of 8,000 m pipeline for the water supply of Hacınınoğlu Village has been constructed by the company. The villagers worked for the company during the completion of the piping. The primary school buildings in Demirlik Village and Kürtül Village are renewed and another one is rebuilt. Stationery sets, including primer, notebook, eraser, pencil sets and sharper, have been distributed to the students in the primary schools in the region (Figure.1).

1 http://www.teias.gov.tr/istatistik2009/41.xls


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Figure.1. Meymendi Primary School 1.2 Sectoral Scope and Project Type

• According to UNFCCC sectoral scopes definition for CDM projects, the Project Activity is included in the Sectoral Scope 1, category “Energy industries (renewable - / non-renewable sources)”.

• The project is a single greenfield investment and is not part of a project group or bundle.

1.3 Project Proponent

Project proponent and their roles and responsibilities are defined in Table.2. Table.2. Project proponent Project Participant Contact Person and Details Roles and Responsibilities Enerjisa Enerji Üretim A.Ş. (private entity)

Đpek Taşgın, Environmental Engineer Ceyhun Atıf Kansu Cd. ,Ehlibeyt Mah., Başkent Plaza No:106 Kat:7-8 Balgat-Ankara [email protected]

Operation of power plant, management of the personnel and implementation of the monitoring plan and owner of the carbon credits.

1.4 Other Entities Involved in the Project

There is no other entity involved.

1.5 Project Start Date

01.04.2013, Commissioning date of the power plants.

1.6 Project Crediting Period

o Crediting period start date: 01.04.2013 o Crediting period end date: 01.04.2023 o VCS project crediting period: 10 years renewable twice


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1.7 Project Scale and Estimated GHG Emission Reductions or Removals

• The proposed project is a bundle of two projects. The first project, Sarıgüzel HEPP is a large scale hydro power plant with an installed capacity of 98.88 MWe and the average annual energy generation is estimated to be 281.191GWh. The project also utilizes the tail water flow for electricity generation with a second project, Sarıgüzel-1 HEPP with an installed capacity of 3.66 MWe and an average annual generation of 30.572 GWh. The total installed power adds up to 102.54 MWe and the average annual generation is 311.763 GWh. • The estimated emission reduction achieved will be 185,811 tonnes CO2 per annum. The total emission reductions during the chosen crediting period will be 1,858,100 tonnes CO2 (Table.3).

Project X

Mega-project

Table.3. Emission reduction to be achieved by the proposed project.

Years Estimated GHG emission reductions or removals (tCO2e)

01.04.2013 139,358

2014 185,811

2015 185,811

2016 185,811

2017 185,811

2018 185,811

2019 185,811

2020 185,811

2021 185,811

2022 185,811

01.04.2023 46,453

Total estimated ERs 1,858,110

Total number of crediting years 10

Average annual ERs 1,858,110

1.8 Description of the Project Activity

The project will utilise the net head loss 109.11m of Ceyhan River with two power stations, namely Sarıgüzel HEPP and Sarıgüzel-1 HEPP for electricity generation (Figure.1.). The reservoir will not serve for irrigation purposes or supply water for other types of usages.


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Figure. 2. The process diagram for Sarıgüzel HEPP and Sarıgüzel-1 HEPP The components of the Projects the dam and their technical specification are as follows: Dam: The maximum operational water elevation is 869.74m. The dam will be built as sand-gravel block with concrete front. The active volume of the dam is 13.64 x 106 m3 and the area of the impoundment lake 1.889 km2 at normal water level. Diversion Conduits and Upstream Cofferdam: The diversion conduit will be built as two units, one of them to provide necessary water flow to the small size Sarıgüzel-1 HEPP and will be released downstream for aquatic life continuity. The tunnel will be 330.00 m with a diameter of 4.50 m. The upstream cofferdam will have crest dimensions of 170.5 m length and 12.0~55.0 m width. Spillway: The spillway consists of 6 gates with dimensions 8.00 m X 13.00 m separated with 3.0 m width walls. It is designed to carry the over flow rate of 4,620 m3/sec. Energy Tunnel: The water taken at 811.55 m elevation and will be carried with an energy tunnel 5,457.23 m length, connected to valve room at 791.00 m elevation. Gate shaft and Surge Chamber: A gate shaft will be placed at Tunnel 5 +111.152nd kilometer with an inside diameter of 16.0 m. A surge chamber will also be placed between elevations 898.00 m and 802.00 m. Penstock and Valve Room: The penstock will be 134.978 m length with a diameter of 5.0-2.80 m and will be placed after valve room. Powerhouse: The powerhouse will be placed on the left side of the coast with a tail water elevation of 747.00 m. There will be two vertical axes Francis type turbines, each having an installed capacity of 49.44 MWe, 50.40 MWm. A tail water channel will be built in order to carry turbinated water to riverbed. The annual average electricity generated is estimated to be 281.191 GWh. The origin of the technology is Austria.


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Sarıgüzel-1 HEPP: Through a penstock with 1.20-1.50 m diameter, built inside the derivation tunnel, the water will be carried to powerhouse and turbinated for electricity generation. The installed capacity will be 3.66 MWe with a constant flow rate of 5.40 m3/sec. The annual electricity generation is estimated to be 30.572 GWh. The origin of technology is Czech Republic. Switchyard and Transmission of electricity: An open switchyard with 154 kV capacity will be placed nearby the power house of Sarıgüzel HEPP. The electricity will be transferred to Kandil HEPP via 12.50 km line and to Hacınınoglu HEPP via 9.50 km line and then fed to the grid by the nearest substations. Access roads: The project site is accessed by Kahramanmaraş-Göksun motorway. At the 45th km of the motorway there is 26 km access road to Ilıca Town and then 23 km road to Hacınınoğlu Village. In addition, 4 km of the existing road will be remedied, 2 km of new road will be constructed and 2 km of road will be relocated in the context of the project. The impact of Kandil Energy Group Projects on the existing and planned dams and hydropower plants upstream and downstream are evaluated during the feasibility studies. There are 3 hydropower plants operational on Ceyhan River in the region. The greatest one is Menzelet Dam and Hydropower Plant which was operational in 1992, with an installed capacity of 124 MW and 515 GWh annual average electricity generation. Sır Dam and Hydropower Plant was operational in 1991 and generates 725 GWh electricity annually. The third one, Ceylan Hydropower Plant is the oldest plant in the region and operational since 1958. Klavuzlu Dam and Hydropower Plant is under construction and will generate 100 GWh electricity with an installed capacity of 50 MW. The dam will also serve the irrigation of 96,963 ha. agricultural land and supply cooling water to Afşin-Elbistan Thermal Power Plant. Adatepe Dam is also under construction and will serve the irrigation of 44,030 ha. agricultural land. The water requirements of all those structures operational and under construction have been calculated. The planned dams and hydropower plants are also taken into consideration during the optimization of electricity generation of Kandil Energy Group Projects. The environmental flow required for the aquatic life for each project in the group are calculated and added to the total water requirement of the development. According to the methodology applied, the baseline scenario for the installation of a new grid-connected renewable power plant is defined as: “Electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources, as reflected in the combined margin (CM) calculations described in the “Tool to calculate the emission factor for an electricity system”. The project generates electricity from renewable resources and therefore replaces electricity which would be generated by Turkish grid dominated with fossil fired power plants. 1.9 Project Location

The Project is located on the Ceyhan River in the Upper Ceyhan Basin within the boundaries of Kahramanmaraş Province in the Eastern Region of Turkey. The nearest residential areas are Sarıgüzel Village, Hacınınoğlu Village and Demirlik Village in Ilıca Town (Figure.3). The coordinates of the project structure are given in table below and demonstrated in Figure 4.


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Figure.3. The location of the project Name of the structure Lattitude Longitude Dam Body 37.935022 36.970558 Spillway 37.933958 36.968278 Sarıgüzel-1 HEPP 37.933712 36.969499 Sarıgüzel HEPP &Switchyard 37.901078 36.970967


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Figure.4. The detailed view of the project site location.


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1.10 Conditions Prior to Project Initiation

The project is a Greenfield project, prior the project initiation, there was no other hydro power installation at the site. 1.11 Compliance with Laws, Statutes and Other Regulatory Frameworks

The project received all authorizations and permits to operate, proving that the project is in compliance with all laws and regulations of Turkey. The table below summarizes the laws and regulations related with the project development and implementation. Table.4. Relevant laws and regulations

Relevant Laws Number / Enactment Date

Aim and Scope

Environmental Law2 *Environmental Impact Assessment Regulation3

Nr. 2872 / 16.12.2003

The approval is requested for power plants from Ministry of Environment and Forest as Electricity Licence Regulation requests project to be in line with the environmental law.

Electricity Market Law4 *Electricity Licence Regulation5 *Electricity Market Balancing and Conciliation Regulation6

Nr. 4628 / 03.03.2001

Regulating procedures of electricity generation, transmission, distribution, wholesale, retail for legal entities. Two regulations issued under the law; one for generation licence and the other for market price balancing and conciliation.

Law on Utilization of Renewable Energy Resources for the Purpose of Generating Electrical Energy7

Nr. 5346 / 18.05.2005

Aims to extend the utilization of renewable energy for electricity generation and identifies method and principles for power generation from renewable resources in an economical and conservative manner.

Energy Efficiency Law8 Nr. 5627 / 02.05.2007

Identifies method and principles for industry, power plants, residential buildings and transport to imply necessary measures for energy efficiency during electricity generation, transmission, distribution and consumption.

2 http://www2.cevreorman.gov.tr/yasa/k/2872.doc 3 http://www2.cevreorman.gov.tr/yasa/y/26939.doc 4 http://www.epdk.gov.tr/mevzuat/kanun/elektrik/elektrik_piyasalari_kanunu.pdf 5 http://www.epdk.gov.tr/mevzuat/yonetmelik/elektrik/lisans/lyson.doc 6 http://www.epdk.gov.tr/mevzuat/yonetmelik/elektrik/dengeleme/yeni/duyson.doc 7 www.epdk.gov.tr/mevzuat/diger/yenilenebilir/yenilenebilir.doc 8 www.eie.gov.tr/duyurular/EV/EV_kanunu/EnVerKanunu_Temmuz2008.pdf


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1.12 Ownership and Other Programs

1.12.1 Proof of Title

Ownership of the plant, equipment and electricity generation licence belongs to Enerjisa Enerji Üretim A.S. and all emission reductions/removals are granted to the company. 1.12.2 Emissions Trading Programs and Other Binding Limits

The project will not be used for compliance with an emissions trading program or to meet binding limits on GHG emissions.

1.12.3 Participation under Other GHG Programs

Not applicable 1.12.4 Other Forms of Environmental Credit

The project has not created another form of environmental credit or renewable energy certificate. 1.12.5 Projects Rejected by Other GHG Programs

1.13 Additional Information Relevant to the Project

Eligibility Criteria

The project is not a part of grouped projects.

Leakage Management

No leakage is considered as per the applied methodology, ACM0002, version 12.2.0

Commercially Sensitive Information

All contracts signed by other parties for construction, purchase of electromechanical equipment and turbine manufacture, maintenance and service , board decisions are commercially sensitive information.

Further Information

The project has been developed strictly according to the legal procedures described above in section 1.10 and managed to be legitimate during all processes. In addition to local environmental legal procedures, the project follows environmental and social standards of International Finance Corporation (Performance Standards, Equator Principles) and audited by Finance Institutions from time to time as well. The emission reductions achieved by the project will be calculated in accordance with the approved methodology ACM0002 version 12.2.0 and the information of the eligibility and quantification of the emission reduction are presented in other sections of the PD. Otherwise, the project considers the revenue of carbon asset sales at the stage of feasibility studies.


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2 APPLICATION OF METHODOLOGY

2.1 Title and Reference of Methodology

The emission reductions of the Project have been calculated in accordance with the approved large scale CDM-methodology ACM0002 .: “Consolidated methodology for grid connected electricity generation from renewable sources”, version 12.2.09. The methodology refers to the “Tool to calculate the emission factor for an electricity system”, version.2.2.1 for baseline calculations. The tool offers two options of which the Combined Margin (CM) approach has been chosen. The CM consists of the combination of operating margin (OM) and build margin (BM) according to the procedures prescribed in the above-mentioned tool. For the demonstration of additionality, “Tool for the demonstration and assessment of additionality”, version 6.0.06.0.0 has been implemented. The methodology also refers to the following two tools:

• “Combined tool to identify the baseline scenario and demonstrate additionality” which is only applicable if the potential alternative scenarios to the proposed project activity available to project participants cannot be implemented in parallel to the proposed project activity. Therefore, the tool is not applicable to the proposed projects.

• “Tool to calculate project or leakage CO2 emissions from fossil fuel combustion” which is applicable

to geothermal and solar thermal projects, which also use fossil fuels for electricity generation for the calculation of Fossil Fuel Combustion (PEFF,y), described in page 6/20 of the methodology. As the projects are not geothermal or solar thermal projects, the tool is not applicable.

2.2 Applicability of Methodology

The choice of large scale CDM methodology ACM0002, version 12.2.0 has been justified through the applicability criteria listed below: Applicability Criteria Justification • This methodology is applicable to grid-connected renewable power generation project activities that (a) install a new power plant at a site where no renewable power plant was operated prior to the implementation of the project activity (greenfield plant); (b) involve a capacity addition; (c) involve a retrofit of (an) existing plant(s); or (d) involve a replacement of (an) existing plant(s).

The projects are grid-connected renewable power generation projects which install a new power plants at a site where no renewable power plant was operated prior to the implementation of the project activity (Greenfield plant).

• The project activity is the installation, capacity addition, retrofit or replacement of a power plant/unit of one of the following types: hydro power plant/unit (either with a run-of-river reservoir or an accumulation reservoir), wind power plant/unit, geothermal power plant/unit, solar power plant/unit, wave power plant/unit or tidal power plant/unit;

The projects are installation of hydro power plants with an accumulation reservoir.

• In the case of capacity additions, retrofits or replacements (except for wind, solar, wave or tidal power capacity addition projects which use Option 2: on page 11

The project are not a capacity addition, retrofit or replacement.

9 http://cdm.unfccc.int/filestorage/L/T/U/LTUGMDQZP69E472IOYK8XR0CBHFV1J/Consolidated%20baseline%20methodology%20for%20grid-connected%20electricity%20generation%20from%20renewable%20sources.pdf?t=R1d8bHkxbXZyfDDVnz8J8gP7nV_5Biy9fMuG


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to calculate the parameter EGPJ,y): the existing plant started commercial operation prior to the start of a minimum historical reference period of five years, used for the calculation of baseline emissions and defined in the baseline emission section, and no capacity expansion or retrofit of the plant has been undertaken between the start of this minimum historical reference period and the implementation of the project activity; • In case of hydro power plants, one of the following conditions must apply: o The project activity is implemented in an existing reservoir, with no change in the volume of reservoir; or o The project activity is implemented in an existing reservoir, where the volume of reservoir is increased and the power density of the project activity, as per definitions given in the Project Emissions section, is greater than 4 W/m2; or o The project activity results in new reservoirs and the power density of the powerplant, as per definitions given in the Project Emissions section, is greater than4 W/m2.

The project activities results in a new reservoir and the power density is 54W/m2 (101,910 x106W/ 1,889,000 m2) and is greater than 4 W/m2.

In case of hydro power plants using multiple reservoirs where the power density of any of the reservoirs is lower than 4 W/m2 all the following conditions must apply: • The power density calculated for the entire project activity using equation 5 is greater than 4 W/m2; • Multiple reservoirs and hydro power plants located at the same river and where are designed together to function as an integrated project that collectively constitute the generation capacity of the combined power plant; • Water flow between multiple reservoirs is not used by any other hydropower unit which is not a part of the project activity; • Total installed capacity of the power units, which are driven using water from the reservoirs with power density lower than 4 W/m2, is lower than 15MW; • Total installed capacity of the power units, which are driven using water from reservoirs with power density lower than 4 W/m2, is less than 10% of the total installed capacity of the project activity from multiple reservoirs.

• There are two hydro power plants, under construction, upstream of the project activity:

1) Dağdelen HEPP, small scale

Power Density =8,000,000 W/ 1,000,200= 8W/m2

2) Kandil Dam and HEPP, large scale Power Density=203,200,000 W/14,550,000 m2 = 14 W/m2 The power densities are higher than 4 W/m2. • The power plants are located on the same

river. • There are no hydropower untis between

the projects. • The power densities are higher than 4

W/m2.

2.3 Project Boundary

The greenhouse gases and emission sources included in or excluded from the Project boundary are compiled in Table.5 below:

Table.5. Emission sources included or excluded from the Project boundary.


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Source Gas Included? Justification/Explanation

Bas

elin

e

CO2 emissions that are displaced due to the Project Activity from electricity generation in fossil fuel fired power plants connected to national grid

CO2 Yes Main emission source. The dominant emissions from power plants are in the form of CO2, therefore CO2 emissions from fossil fuel fired power plants connected to the grid will be accounted for in baseline calculations.

CH4 No Minor emission sources.

N2O No

Other No

Pro

ject

Emissions as a result of Project Activity

CO2 No Minor emission source. As suggested by the baseline methodology, project emissions (PEy) are assumed to be 0 and will not be considered.

CH4 No

N2O No

Other No

2.4 Baseline Scenario

The baseline scenario has been developed by the assumption that the energy generation profile of the country will not change and the weight of fossil fired power plants will remain the same during the crediting period. The electricity generation is mainly done by fossil fuel fired power plants in Turkey. The share of resources in the electricity generation in Turkey has been shown in the Figure.5. 80.3% of the total electricity generation delivered by fossil fired power plants, i.e. natural gas, lignite, hard coal, imported coal and liquid fuels10. The contribution to annual electricity generation form hydraulic resources was only 18.5%.

Figure.5. The share of resources for electricity generation. It is assumed that the energy generation profile of the country will not change and the weight of fossil fired power plants will remain the same during the crediting period. This assumption is based on the analysis presented in the First National Communication11 submitted by Turkey. The share of resources in generating capacity between 2005-2020 is shown in Figure.6.

10 Annual report, Electricity Generation Company, 2009 (http://www.euas.gov.tr/_EUAS/Images/Birimler/apk/2009%20YILLIK%20RAPOR%20B%C3%96L%C3%9CM-1.pdf) 11 http://iklim.cob.gov.tr/iklim/Files/turnc1.pdf


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The baseline scenario is the same amount of electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources.

Figure.6. Electricity Generation Forecast (2005-2020)

Power generation has been the greatest contributor source to GHG emissions with a share of 76.7% in 2004 as stated in the First Communication of Turkey on Climate Change (pg:243, Annex.4). The continued reliance on fossil fuels in the power sector will give rise to emissions in the following years. The power sector sourced GHG emission is expected to rise 7.1% every year during 2003-2020. 2.5 Additionality

“Tool for the demonstration and assessment of additionality” version 6.0.0 has been implemented to the Project. Step 1- Identification of alternatives to the project activity consistent with current laws and regulations Sub-step 1a: Define alternatives to the project activity: The project owner is a well-known company in the power sector and active in generation, wholesale and trading and distribution of electricity. The company has established four natural gas power plants with a total installed capacity of 1,385 MW. Five hydropower plants with a total installed capacity of 227 MW and a wind power plant with 30 MW capacity are operational12. The alternatives are defined related to the investor as per footnote 4 of the version 6.0.0 of the additionality tool13: 1) The project activity taken without VER: The investment is not financially attractive and comprises potential risks as described below. Therefore, this alternative is not realistic. 2) Building a new power plant utilizing other renewable resource: The Electricity Market License Regulation gives priority to local resources with low environmental impact to generate electricity14 and therefore other renewable resources are considered as alternatives to the proposed project.

12 http://www.enerjisa.com.tr/en/ 13 As per footnote 4 of the version 6.0.0 of the additionality tool 14 Sub-clause (5) of Article.9 (http://www.epdk.gov.tr/mevzuat/yonetmelik/elektrik/lisans/lyson.doc)


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Figure.7. below shows the wind power capacity of Kahramanmaraş Province. The speed of the wind should over 7 m/sec for an economically feasible power generation and the regions with gray colour are not eligible for power generation. Therefore wind power plant is not alternative for the proposed project (Figure.7.)15. Geothermal resources eligible for electricity generation are located on the West of the country and there are three power plants operational in that region. Using solar power or biomass for electricity generation is still in the infancy state in Turkey. There are no solar or biomass power plants in Turkey16 due to insufficient incentives. Therefore, utilizing other renewable resources is not a realistic and credible alternative scenario to the proposed project activity.

Figure.7. Eligibility of Kahramanmaraş province for wind power. 3) No activity: In case no project activity is taken, the same amount of electricity will be generated by the existing grid to supply the increasing demand of the country. This alternative is the same as baseline scenario, which is described above as electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources. Outcome of Step 1a) The only realistic and credible scenario is that the same amount of electricity will be generated by the existing grid, which is the same as baseline scenario. Sub-step 1b: Consistency with mandatory laws and regulations: All alternatives to the project activity are in compliance with the existing laws and regulations which are described above in Table.2., section 1.10. Outcome of Step1b: The only realistic scenario is the supply of same amount of electricity from the existing grid, which is in compliance with the laws and regulations. Step 2 - Investment analysis The investment analysis below aims to show that “the proposed project activity is not (a) the most economically and financially attractive”. Sub-step 2a - Determine appropriate analysis method (1)There are three options for investment analysis method: • Simple Cost Analysis • Investment Comparison Analysis and • Benchmark Analysis

15 http://www.eie.gov.tr/duyurular/YEK/YEKrepa/ADANA-REPA.pdf 16 Ek-1: Mevcut Sistem (http://www.teias.gov.tr/projeksiyon/KAPASITEPROJEKSIYONU2009.pdf)

v3.0

As the project gains revenue from the sale of generated electricity, Simple Cost Analysis iInvestment Comparison Analysis is also not applicable as no alternative investment is point at issue. Therefore, Benchmark Analysis will be used for the evaluation of the project investment. Sub-step 2b - Option III-Apply benchmark For the purpose of benchmark analysis project IRR has been chosen as the indicator. Annex: Guidance on the Assessment of Investment Analysis (version 02WACC are appropriate benchmarks for a p There are no available benchmarks for hydro power plant projects in Turkey. The credibility of a particular project is evaluated on the basis of several factors including cost recovery period, risk of postponed commissioning and credibility of the project owner. The long term financing is limited and therefore most of the large hydro power plants were built by public. Please see Step.4 below for information on private hydro power plants. World Bank has released 500 M USD fund for private seon May 2009. The loan is given through two local ban(TSKB) and Turkish Development Bank (TKB). The fund is available for small hydro power plants with installed capacity less than 10 MWs and a reservoir area limited to less than 15 kmIn the project appraisal report it is stated that “of 15 percent.”17. That benchmark reflects the bankers view on the IRR for small scale hydropower plants. The proposed project is a large scale hydro power planttherefore the financial risks and investment climate would not be comparable to th As the tool implies local commercial lending rates or weighted average costs of capital (WACC) are appropriate benchmarks for a project IRR. Therefore, those two alternatives are discussed below:

1) Local Lending Rates The lending rates for medium term investments provided by Turkish Development Bank to State Planning Organization are used as the benchmark. The maturity of loan, depending on the project characteristics and may change between 5 to 7 years with 2 years grace period. The benchmark is found to be appropriate for hydroelectric power projects which are expected to to return the investment in 5-10 years18. As seen from the figure below, Atatürk, Karakaya and Keban hydroelectric power plants have recovered their cost in 9, 4 and 7 years respectively. Figure.8. Cost recovery and profit periods for hydroelectric power plants in Turkey

17 http://www-wds.worldbank.org/external/default/WDSContentServer/WDSP/IB/2009/05/11/00fficial0Use0Only1.pdf (Annex.11, Article 29, page 80)18 http://www2.dsi.gov.tr/english/service/enerjie.htm

PROJECT DESCRIPTION

As the project gains revenue from the sale of generated electricity, Simple Cost Analysis iInvestment Comparison Analysis is also not applicable as no alternative investment is point at issue. Therefore, Benchmark Analysis will be used for the evaluation of the project investment.

Apply benchmark analysis

For the purpose of benchmark analysis project IRR has been chosen as the indicator. Annex: Guidance on the Assessment of Investment Analysis (version 02.2.0) indicates that local commercial lending rates or WACC are appropriate benchmarks for a project IRR.

There are no available benchmarks for hydro power plant projects in Turkey. The credibility of a particular project is evaluated on the basis of several factors including cost recovery period, risk of postponed

of the project owner. The long term financing is limited and therefore most of the large hydro power plants were built by public. Please see Step.4 below for information on private hydro

World Bank has released 500 M USD fund for private sector renewable energy and energy efficiency projects on May 2009. The loan is given through two local banks, namely, Turkish Industrial D(TSKB) and Turkish Development Bank (TKB). The fund is available for small hydro power plants with

alled capacity less than 10 MWs and a reservoir area limited to less than 15 kmIn the project appraisal report it is stated that “In Turkey, typical developer of small hydro expects equity IRRs

reflects the bankers view on the IRR for small scale hydropower plants. The proposed project is a large scale hydro power plant with a small scale tail

the financial risks and investment climate would not be comparable to the small scale projects.

As the tool implies local commercial lending rates or weighted average costs of capital (WACC) are appropriate benchmarks for a project IRR. Therefore, those two alternatives are discussed below:

ates for medium term investments provided by Turkish Development Bank to State Planning Organization are used as the benchmark. The maturity of loan, depending on the project characteristics and may change between 5 to 7 years with 2 years grace period.

The benchmark is found to be appropriate for hydroelectric power projects which are expected to to return . As seen from the figure below, Atatürk, Karakaya and Keban hydroelectric

power plants have recovered their cost in 9, 4 and 7 years respectively.

Cost recovery and profit periods for hydroelectric power plants in Turkey

wds.worldbank.org/external/default/WDSContentServer/WDSP/IB/2009/05/11/000333037_20090511030724/Rendered/PDF/468080PAD0P112101O(Annex.11, Article 29, page 80)

http://www2.dsi.gov.tr/english/service/enerjie.htm


19

As the project gains revenue from the sale of generated electricity, Simple Cost Analysis is not applicable. Investment Comparison Analysis is also not applicable as no alternative investment is point at issue. Therefore, Benchmark Analysis will be used for the evaluation of the project investment.

For the purpose of benchmark analysis project IRR has been chosen as the indicator. Annex: Guidance on ) indicates that local commercial lending rates or

There are no available benchmarks for hydro power plant projects in Turkey. The credibility of a particular project is evaluated on the basis of several factors including cost recovery period, risk of postponed

of the project owner. The long term financing is limited and therefore most of the large hydro power plants were built by public. Please see Step.4 below for information on private hydro

ctor renewable energy and energy efficiency projects ks, namely, Turkish Industrial Development Bank

(TSKB) and Turkish Development Bank (TKB). The fund is available for small hydro power plants with alled capacity less than 10 MWs and a reservoir area limited to less than 15 km2 (page 11 of the report).

In Turkey, typical developer of small hydro expects equity IRRs reflects the bankers view on the IRR for small scale hydropower plants.

with a small scale tail-water power plant and e small scale projects.

As the tool implies local commercial lending rates or weighted average costs of capital (WACC) are appropriate benchmarks for a project IRR. Therefore, those two alternatives are discussed below:

ates for medium term investments provided by Turkish Development Bank to State Planning Organization are used as the benchmark. The maturity of loan, depending on the project characteristics and

The benchmark is found to be appropriate for hydroelectric power projects which are expected to to return . As seen from the figure below, Atatürk, Karakaya and Keban hydroelectric

Cost recovery and profit periods for hydroelectric power plants in Turkey

0333037_20090511030724/Rendered/PDF/468080PAD0P112101O


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State Planning Organization publishes “Main Economic Indicators” on a monthly basis. The lending rates for January-May 2008 have been given in Table.619.

Table.6. Loan Interest rates for medium term investment loans

Turkish Development Bank (TKB) Interest rates for credits

Date Month Medium Term Investment Rate(%)

2008

1 19 2 19 3 19 4 19 5 19

The investment decision was taken on the 16.04.2008. Therefore, the interest rate for April is taken as the benchmark, which is 19.0%.

2) Weighted Average Cost of Capital, WACC The second alternative for benchmark is advised to be WACC for project IRR as stated in the referenced tool. The expected return on capital should be higher than the cost of capital for an investment to be worthwhile. The cost of capital is the rate of return that capital could be expected to earn in an alternative investment of equivalent risk. If a project is of similar risk to a company's average business activities it is reasonable to use the company's average cost of capital as a basis for the evaluation. A company's securities typically include both debt and equity, one must therefore calculate both the cost of debt and the cost of equity to determine a company's cost of capital. Calculation of Cost of Equity: In order to calculate the cost of equity, the approach presented in the paper “Estimating equity Risk Premiums” by Prof. Damodaran is taken20. He is a Professor of Finance at the Stern School of Business at Newyork University and well known as author of several widely used academic and practitioner texts on Valuation, Corporate Finance and Investment Management. Most of the parameter used in calculations are taken from the data presented in his web site. Since the private sector inclusion to the energy market is in a very early stage in Turkey, compared to mature markets in other countries, we assume that all companies investing an emerging market would be equally exposed to country risk. The following formula is used for expected cost of equity: Expected cost of Equity=Risk free rate + β*( Country Risk) + Equity Market Risk

1) Choice of Risk free rate: It is stated in the referenced paper that the risk free rate chosen should match up with the duration of the cashflows being discounted and long-term default free government bond rate are generally preferred in corporate finance and valuation. Therefore,the risk free rate is taken from the lowest yielding bonds in the particular market, i.e. government bonds. The rate of Eurobond US900123AL40 with a due date 15.01.2030 has been chosen as the duration of the cash flow is 20 years. The rate on 16/04/2008 has been taken as the risk free rate.

2) Choice of beta: The beta value for Turkish electiricty market is available from Bloomberg data. The Electricity Index value for 2008 is used.

3) Choice of Country Risk and Equity Market Risk:

19 Main Economical Indicators, 7.Bolum, Table.13., (http://ekutup.dpt.gov.tr/teg/2008/12/tvii.13.xls) 20 http://pages.stern.nyu.edu/~adamodar/pdfiles/papers/riskprem.pdf


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One of the simplest and most easily accessible measure of the country risk is the rating assigned to a country’s debt by a ratings agency. These rating measure default risk but they are affected by many of the factors that drive equity risk. The country risk for Turkey has been taken from updated data in 2008 by Prof. Damodoran. The equity market risk for US, including average of historical spreads over 5 years has been used from the same data sheet. The following parameters are used for calculation: Parameter Value Source Risk free rate 7.22% Ziraat Bank, Long term Eurobond rate,

(US900123AL40) on 16/04/200821

Beta 0.778 Beta for electricity market in Turkey in 2008, Bloomberg

Country Risk 7.88% Prof. Damodaran, Risk Premium for Other Markets, 2008, Country Risk Premium for Turkey22

Equity Market Risk 5.00% Prof. Damodaran, Risk Premium for Other Markets, 2008, Equity Risk Premium for US market23

Expected Cost of Equity 18.35% Calculated

Calculation of Cost of Debt: The interest rate for the project has been taken as 9.5%, which is the value used in the invesment analysis done in the Feasibility Report dated November 2007 (page 8-72). Calculation of WACC: The Weighted Average Cost of Capital (WACC) for the project has been calculated by the following formula:

( )cTV

ECE

V

DCDWACC −+= 1*

The parameters are defined below: Parameter Value Source CD, Cost of Debt 9.5% Annual interest rate, Feasibility Report,

November 2007(page 8-72)

D/V, percentage of financing that is debt

57.06% Calculated

E/V, percentage of financing that is equity

42.94% Calculated

CE, Cost of equity 18.35% Calculated

Tc, Average business revenue tax

0 Since the project IRR is calculated on before-tax basis for the project, revenue tax is not included in the calculation.

WACC 13.30% Calculated

21 http://www.ziraat.com.tr/tr/bankamiz/faiz-ve-ucretler/aspx/eurobond.aspx 22 http://www.stern.nyu.edu/~adamodar/pc/archives/ctryprem08.xls 23 http://www.stern.nyu.edu/~adamodar/pc/archives/ctryprem08.xls


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In order to follow a conservative approach, the WACC as 13.30% is accepted as the benchmark for the proposed project. Sub-step 2c - Calculation and comparison of financial indicators The “Guidance for the assessment of investment analysis”24 implies that: “6. Guidance: Input values used in all investment analysis should be valid and applicable at the time of the investment decision taken by the project participant. “

The following table summarizes the financial figures for the project operation. Please be informed about the fact that the first revision of the feasibility report was done in November 2007 and those figures were available at the time of the investment decision.

Table.7. Summary of financial data

Parameter used for financial analysis

unit value Source

Expected Electricity Generation

MWh 247,057

As per “Guidelines for reporting and validation of plant load factors”25 , the plant load factor is calculated by a third party for the feasibility report, Nov 2007.

Total Investment USD 131,106,565

Feasibility Report, Nov.2007

Operation and Maintanance Cost

USD 1,358,905

Feasibility Report, Nov.2007

Feed-in tariff USDcent 7.3 Renewable Energy Law Nr.5346.

Revenues USD/year 18,035,161

Electricity revenues were estimated based on the highest value of the range given by renewable energy law Nr.5346.

Exchange rate USD/EUR 1.370351 Annual average for 2007, exchange rate: http://www.oanda.com/currency/average

The Internal Rate of Return (IRR) before taxation for the project is calculated as 11.38% without the ER revenue. That is much lower than expected interest rates in Table.6. As a result, the revenue acquired from the operation of the power plant is not financially attractive to do the investment. Sub-step 2d - Sensitivity Analysis The sensitivity analysis is applied to variables that constitute of the total investment cost in order to show that investment decision is not the most attractive alternative financially. Operation and maintanance cost is 1% of the the total investment cost, the electricity revenue is 14% of the investment cost. Therefore only investment cost is taken into account in the sensitivity analysis and the change in electricity revenue is discussed for the avoidance of the doubt. For a range of ±10% fluctuations in parameters above, Table.8. below have been obtained.

24 http://cdm.unfccc.int/EB/051/eb51_repan58.pdf 25 http://cdm.unfccc.int/EB/048/eb48_repan11.pdf


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Table.8. Sensitivity analysis for the Project IRR

IRR w/o carbon -10% -5% 5% 10%

Benchmark hitting

percentage

Investment Cost 11.67 11.52 11.24 11.10 -60%

The project IRR becomes 11.67% with a 10% decrease in investment costs.The investment cost is not likely to decrease but has increased as stated in the feasibility report revised in November 2010. As the design of upstream and downstream hydropower plants of Kandil group changed, Sarıgüzel Dam and Hydrolectric Power Plants are revised accordingly. The investment analysis done for the project in November 2010 are compared to the previous figures in 2007 in the below Table.9. Table.9. Comparison of financial data on November 2007 and November 2010. Parameter used for financial analysis unit Value in 2007 Value in 2010 % Change

Expected Electricity Generation MWh 247,057

311,763 +26.2

Total Investment USD 130,884,565

214,928,313 +67

Operational Cost USD 1,358,905

1,817,659 +64

Revenues USD/year 18,035,161

22,758,699 +26.2

Exchange rate USD/EUR 1.37035 1.32747 -3

IRR 11.4 8.9 -22

The investment cost and operational cost have risen by more than 50% in return of the increased electricity generation and revenue. Therefore, decrease in investment cost or operational cost could not be expected. The exchange rate has fallen but the IRR of the project drops to 8.9% in the final case. The change in the electricity price was not expected by the time of the project decision taking phase. Renewable Energy Law limits the price of electricity generated by renewable resources from a minimum 5 Eurocents to maximum 5.5 Eurocenst per kWh with a purchase guarantee of maximum 10 years. The law came into force recently in 2005. A revision made to the law in January 2011 but the price offered for hydropower plants did not change. It is now 7.3 USDcents/kWh, which is roughly equal to 5.5 EURcents. The electricity price should be 8.4 USDcent/kWh (15% higher) to hit the benchmark of 13.30%; which is not unlikely under those circumstances. Outcome of Step 2: The proposed project is unlikely to be financially attractive. Step 3: Barrier analysis This step is not implemented for the project. Step 4: Common practice analysis Sub-step 4a. Analyze other activities similar to the proposed project activity. According to the requirements of common practice:


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Projects are considered similar if they are in the same country/region and rely on a broadly same technology, are of similar scale and take place in a comparable environment with respect to regulatory framework, investment climate, access to technology, access to financing. The graph below shows the status of the economical hydropower potential of Turkey (Figure.9)26.Only 36% of the total capacity is under operation and 11% is expected to be operational in coming years. The rest, comprising 53%, are awating for investment in February 2007.

Figure.9. Turkey’s Hyroelectric Power Potential Status of the projects The total installed hydropower capacity was 13,828.7 MW in 2008 and generating 33,269.8 GWh of electricity, i.e. 16.76% of total generation (198,418 GWh)27. Table.8. below summarizes the breakdown of the total installed power in terms of ownership. The publicly owned Electricity Generation Corporation (EUAS) has 11,677.9 MW of the total installed capacity, which equals to 80.2%. The privately owned hydroelectric power plants are only 1,328.8 MW, which is 9.1% of the total installed capacity. 37 of those hydropower plants have installed capacity below 1-10 MW, 40 of them ranges between 10-50 MW and 1 has 110.9 MW and one has 97 MW which is Darica HPP,registered as VCS 506(Annex.1, (2010-2019) report)28.

Table.10.Ownership of hydropower capacity Ownership Hydropower

Capacity Share in Total Hydropower Capacity

EUAS 11,677.9 MW 80.2 % BOT 972.4MW 6.7% Autoproducers 544.2MW 3.7% TOOR 30.1 M W 0.2% Private Generation

1,328.8 MW 9.1%

26 http://www.eie.gov.tr/turkce/YEK/HES/proje/GRAPH-1%20(ana).xls 27 http://www.teias.gov.tr/istatistik2008/13.xls 28 http://www.teias.gov.tr/eng/ApkProjection/CAPACITY%20PROJECTION%202009-2018.pdf (Table 9, page 16)


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Companies TOTAL 14,553.4MW 100%

Remaining is owned by auto producers and transfer of operational right power plants (TOR) and Built, Operate and Transfer power plants. TOR power plants are built by public and transferred to private sector after commissioning. Built, Operate and Transfer model was implemented in 1980s and provided financial incentives for the private sector:

o Energy Fund was established by the government in order to subsidise the financial difficulties faced by the companies. o Guarantee Contract was signed between the Under-secretariat of Treasury and the investment companies on the terms that the electricity will be purchased by Treasury in case the producer could not sell it to any governmental institution. o Those purchase contracts may be up to 99 years for BOTs and 20 years for BOs29.

Under the new Electricity Market Law that came in force in 2001, the investment models were removed and the Energy Fund was ended. The list of hydropower plants built by private sector after 2001 is given in Annex.4. As it could be seen from the list given, almost half (37 out of 79) of the hydropower plants are mini sized (1-10 MWs). The installed capacity for the rest of hydropower plants, except Akköy-1 HEPP (101.94 MW) and Uzunçayır HEPP (74 MW) changes between 10-50 MWs. Hydropower plants in Turkey are classified as follows30:

a) Large Hydropower Plants with installed capacity over 50 MWs, b) Small Hydropower Plants with installed capacity between 10-50 MW, c) Mini Hydropower Plants with installed capacity between 101 kW-10,000kW, d) Micro Hydropower Plants with installed capacity between 200 W- 100 kW.

For the purpose of common practice analysis, large hydro power plants with capacities higher than 50 MWs in the country are assessed. The power plants developed by private sector are taken into consideration to evaluate a comparable environment with respect to regulatory framework, investment climate, access to technology, access to finance. Table.11. shows the list of power plants developed and operated by private sector in the country. Table.11. The list of hydropower plant as common practices31 Project Name Project Owner Installed

Power (MW)

Annual production (GWh)

Operation year

1 Darıca HEPP YAPISAN 97.0 328 2009 2 Akkoy-1 HEPP AKKÖY ENR. A.Ş. 101.9 408 2008 There are only two hydropower projects large scale and owned by private sector. Darıca HEPP is registered as VCS 506 and excluded from the common practice analysis. Akkoy-1 HEPP has a load factor of 45% which is higher than the proposed project (27%). This means more sale revenues in return of the investment done per MW and will make this project financially more attractive than the proposed one. Sub-step 4b. Discuss any similar options that are occurring.

29 http://www.ydk.gov.tr/seminerler/turkiyede_yid_modeli.htm 30 This classification has been taken from the Project Description file of Beşpınar Hydropower Plant submitted to Ministry of Environment and Forest, (http://www2.cedgm.gov.tr/cedsureci/ced_basvuru_dosyasi/259_ptd.pdf, page 22) 31 http://www.teias.gov.tr/projeksiyon/KAPASITE%20PROJEKSIYONU%202010.pdf (pages 95-96)


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In one hand, privately owned hydroelectric power plants comprise 9.1% of the total hydro power capacity in Turkey. 37 of those hydropower plants have installed capacity below 10 MW, 40 of them ranges between 10-50 MW and 1 has 110.9 MW anad another has 97 MW but registered as VCS. The only project comparable to the proposed project is found to be Akkoy-1 HEPP which has higher load factor and therefore higher electricity revenue in return of the investment done per MW compared to the Projects. This makes the investment more financially risky than the other projects implemented in the country. On the other hand, the Projects are located in a disadvantaged region where the construction works take longer time and higher investment. The commissioning date of the plant is estimated to be after 4 years the construction started; which was assumed as 3 years in the Feasibility Report dated November 2007 at the time of decision making (page 1-14) Outcome of Step4 : Sarıgüzel Dam and HEPPs are not a common practice in the country as well as in the region. 2.6 Methodology Deviations

The methodology deviation proposed for China and accepted by the Executive Board32 is used for the calculation of Build Margin. Please see step.5 and 6 below.

3 QUANTIFICATION OF GHG EMISSION REDUCTIONS AND REMOVALS

3.1 Baseline Emissions

The baseline emissions are the product of electrical energy baseline EGBL, y expressed in MWh of electricity produced by the renewable generating unit multiplied by the grid emission factor: BEy=EGBL,y*EFCO2,grid,y where : EFCO2,grid,y : CO2 emission factor of the grid connected power generation in year y (tCO2/MWh) EGBL,y : Quantity of net electricity supplied to the grid as a result of the implementation of the CDM

project activity in year y (MWh) The Emission Factor can be calculated in a transparent and conservative manner as follows: (a) A combined margin (CM), consisting of the combination of operating margin (OM) and build margin (BM) according to the procedures prescribed in the ‘Tool to calculate the emission factor for an electricity system’(version 2.2.1). OR (b) The weighted average emissions (in kg CO2/kWh) of the current generation mix. The data of the year in which project generation occurs must be used. The data on the current generation mix is not available; therefore method (a) is adopted to calculate the combined margin emission factor. The emission factors are calculated as described in the “Tool to calculate the emission factor for an electricity system” (version 2.2.1) as following seven steps: 32 http://cdm.unfccc.int/UserManagement/FileStorage/AM_CLAR_QEJWJEF3CFBP1OZAK6V5YXPQKK7WYJ


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Step 1. Identify the relevant electricity systems The proposed project is connected to the national grid, so the project electricity system is the national grid which includes the project site and all power plants physically connected to the grid. Each power plant can be dispatched without significant transmission constraints from the central grid (Figure.10).

Figure.10. Interconnected national grid of Turkey33 There is no electricity import from another power grid within the same host country and electricity exports are not subtracted from electricity generation data used for calculating and monitoring the electricity emission factors. 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 chosen. Step 3. Select an operating margin (OM) method The calculation of the operating margin emission factor (EF grid,OM,y ) is based on one of the following methods: (a) Simple OM, or (b) Simple adjusted OM, or (c) Dispatch Data Analysis OM, or (d) Average OM The data specific to the power plants connected to the grid, such as the dispatch order for each power plant in the system and the amount of power dispatched from all plants in the system during each hour, are not available. Therefore, Simple OM has been selected as the methodology. The Simple OM method (a) can only be used if low-cost/must run resources constitute less than 50% of total grid generation in: 1) average of the five most recent years, or

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


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2) based on long-term averages for hydroelectricity production. There is no nuclear plant in Turkey and hydro, wind and geothermal facilities are only renewable sources utilized for electricity. There is no indication that the coal fired power plants are accepted as the low cost /must run. Table.12. below shows the share of hydro and renewable resources in electricity generation for the five most recent years (2005-2009) and it is below 50% of the total grid generation. Table.12. Share of primary sources in electricity generation, 2005 – 200934

YEAR THERMAL HYDRO GEOTHERM.WIND TOTAL GWh % GWh % GWh % GWh

2005 122,242.3 75.5 39,560.5 24.4 153.4 0.1 161,956.2

2006 131,835.1 74.8 44,244.2 25.1 220.5 0.1 176,299.8 2007 155,196.2 81,0 35,850.8 18.7 511.1 0.3 191,558.1

2008 164,139.3 82.7 33,269.8 16.8 1,008.9 0.5 198,418.0

2009 156,923.4 80.5 35,958.4 18.5 1,931.1 1 194,812.9

The Simple OM can be calculated using either of the two following data vintages for year(s) y: • Ex ante option: If the ex ante option is chosen, the emission factor is determined once at the validation stage, thus no monitoring and recalculation of the emissions factor during the crediting period is required. For grid power plants, use a 3-year generation-weighted average, based on the most recent data available at the time of submission of the CDM-PDD to the DOE for validation. • Ex post option: The year in which the project activity displaces grid electricity, requiring the emissions factor to be updated annually during monitoring. If the data required calculating the emission factor for year y is usually only available later than six months after the end of year y,alternatively the emission factor of the previous year (y-1) may be used. If the data is usually only available 18 months after the end of year y, the emission factor of the year proceeding the previous year (y-2) may be used. The same data vintage (y, y-1 or y-2) should be used throughout all crediting periods.

Based on the most recent data available, ex- ante option is chosen. Step 4. Calculate the operating margin emission factor according to the selected method There are two options calculating the Simple OM emission factor (EF grid,OMsimple,y ): Option A: Based on the net electricity generation and a CO2 emission factor of each power unit; or Option B: Based on the total net electricity generation of all power plants serving the system and the fuel types and total fuel consumption of the project electricity system. Option B can only be used if: (a) The necessary data for Option A is not available; and (b) Only nuclear and renewable power generation are considered as low-cost/must-run power sources and the quantity of electricity supplied to the grid by these sources is known; and (c) Off-grid power plants are not included in the calculation. As the data on each power plant/unit is not publicly available and and renewable power generation are considered as low-cost/must-run power sources, Option B is selected. Off-grid power plants are not included in the calculations.

34 Annual Development of Turkey’s Installed Capacity and Generation in Turkey (1970-2009),( http://www.teias.gov.tr/istatistik2009/13.xls)


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The simple OM emission factor is calculated based on the net electricity supplied to the grid by all power plants serving the system, not including low-cost / must-run power plants / units, and based on the fuel type(s) and total fuel consumption of the project electricity system, as follows:

y

iyiCOyiyi

yOMsimplegrid EG

EFNCVFCEF

∑=

)**( ,,2,,

,,

Where: EFgrid,OMsimple,y : Simple operating margin CO2 emission factor in year y (tCO2/MWh) FCi,y : Amount of fossil fuel type i consumed in the project electricity system in year y(mass or volume unit) NCVi,y : Net calorific value(energy content) of fossil fuel type i in year y (GJ/mass or volume unit) EFCO2,i,y : CO2 emission factor of fossil fuel type i in year y(tCO2/MWh) EGy : Net electricity generated and delivered to the grid by all power sources serving the system, not including low-cost/must-run power plants/units, in year y(MWh) i : All fossil fuel types combusted in power sources in the project electricity system in year y y : The three most recent years for which data is available at the time of submission of the CDM-PDD to the DOE for validation (ex ante option). Step 5: Identify the group of power units to be included in the build margin

1) Identification of the available data The sample group of power units m used to calculate the build margin consists of either: a) The set of five power units that have been built most recently, or b) The set of power capacity additions in the electricity system that comprise 20% of the system generation (in MWh) and that have been built most recently. There is not sufficient data available about the power plants built most recently. Annual capacity addition are reported as whole sum of thermal, geothermal+wind and hydro power in MWs with estimated annual electricity generation for the recent three years (200735, 200836 and 200937) but no plant based information on the net electricity generated for operating years is available. The deficiency in the data has been eliminated by a methodology deviation, that has been proposed for China and accepted by the Executive Board38. As Executive Board accepted the following deviations:

1. Use of capacity additions during last 1~3 years for estimating the build margin emission factor for grid electricity;

2. Use of weights estimated using installed capacity in place of annual electricity generation. The Board suggest the following when applying the deviation:

• Use of efficiency level of the best technology commercially available in the provincial/regional or national grid of China, as a conservative proxy, for each fuel type in estimating the fuel consumption to estimate the build margin (BM)

The tool to calculate the emission factor for an electricity system states to select either the 5 most recent power units or the units that comprise at least 20% of the system generation, excluding registered CDM

35 Generation Units Put Into Operation and Out of Operation in 2007,( http://www.teias.gov.tr/ist2007/8.xls) 36 Generation Units Put Into Operation and Out of Operation in 2008 (http://www.teias.gov.tr/istatistik2008/8.xls) 37 Generation Units Put Into Operation and Out of Operation in 2009 (http://www.teias.gov.tr/istatistik2009/8.xls) 38 http://cdm.unfccc.int/UserManagement/FileStorage/AM_CLAR_QEJWJEF3CFBP1OZAK6V5YXPQKK7WYJ


v3.0 30

projects. As the use of weights estimated using installed capacity in place of annual electricity generation will be implemented, 20% of the total installed power units in 2009 will be included in BM calculations.

2) Exclusion of the registered VER projects As per the tool, the projects registered as voluntary emission reduction are excluded from the group of projects: “Power plant registered as CDM project activities should be excluded from the sample group m.” The following projects, operational between 2006-2009, are excluded from the list: Table.13. VER projects in Turkey

Project Name Capacity (MW)

Operation date

Registered as

Kemerburgaz Wind Farm

24 2008 GS503

Dares Datça Wind Farm

29.6 2008 GS438

Akbük Wind Farm 31.5 2009 GS436 Alize Camseki Wind Farm

20.8 2009 GS399

Keltepe Wind Farm 20.7 2009 GS437 Mazi-3 Wind Farm 30.0 2009 GS388 Anemon Intepe Wind Farm

30.4 2007 GS347

Burgaz Wind Farm 14.9 2007 GS439 Sayalar Wind Farm 34.2 2008 GS369 Catalca Wind Power 60 2008 GS367 Mare Manastir Wind Farm

39.2 2006 GS368

Karakurt Wind Farm 10.8 2007 VCS66 Bares-II Wind Farm 30.0 2006 VER + 52-1 Sebenoba Wind Farm 20.0 2008 VER + 0002 (being

transferred to VCS Çaldere HEPP 8.9 2008 VCS363 Kargilik Hydropower Plant

24 2006 VCS264

Kalealti Hydropower Plant

15 2006 VCS111

Darıca-1 Hydropower Plant

99 2009 VCS506

Mamak Landfill Waste Management Project

19.8 2007 GS440

Menderes Geothermal Power plant

8.0 2008 VCS120

TOTAL CAPACITY 570.8 MW The installed capacity is 44761.2 MW in 2009 and 20% of the capacity is calculated as 8,952.2 MW. Summing up the capacity additions through 2002-2009 and subtracting registered VER projects; an amount of 12,228.2 MW is reached.

3) Determining the efficiency level of the best technology commercially available


v3.0 31

As per the suggestion of the Board to use of efficiency level of the best technology commercially available, proportional weights that correlate to the distribution of installed capacity in place during the selected period above should be applied. The efficiency data for power plants are not available for best practice technologies utilized in Turkey. However, efficiency for each fuel type could be calculated directly from Heating Values given for each fossil fuel type (i) in each year (y) divided by the Electricity Generated by that type of fuel-fired power plants in that year:

100*16393.1*,

,,

yi

yiyi ueHeatingVal

EGEfficiency =

Where:

Efficiencyi,y : Efficiency for the fossil fuel type i for year y (%) Heating Valuei,y : Heating Value for the fossil fuel type i for year y (Tcal) EG i : Electricity generation by the fossil fuel type i in year y (GWh)

The efficiencies of each fossil fuel type for each year in the period of 2002-2009 have been calculated and the maximum value for each fossil fuel type is used.

4) Determining the vintage

In terms of vintage, there two options defined: 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 CDM-PDD submission to the DOE for validation. For the second crediting period, the build margin emission factor should be updated based on the most recent information available on units already built at the time of submission of the request for renewal of the crediting period to the DOE. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. This option does not require monitoring the emission factor during the crediting period. Option 2: For the first crediting period, the build margin emission factor shall be updated annually, ex post, including those units built up to the year of registration of the project activity or, if information up to the year of registration is not yet available, including those units built up to the latest year for which information is available. For the second crediting period, the build margin emissions 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 for the data vintage. STEP 6. Calculate the build margin emission factor. The build margin emission factor is the generation-weigthed average emission factor (tCO2/MWh) of all power units m during the most recent year y for which power generation data is available, calculated as follows:

∑

∑=

mym

mymELym

yBMgrid EG

xEFEGEF

,

,,,

,,

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


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m: Power units included in the build margin y: Most recent historical year for which electricity generation data is available The BM calculation adopts the modifications methods agreed by the CDM EB. The weighted average of the installed capacity of each fossil fuel type should be used instead of EG values. Therefore the equation is:

∑

∑=

mym

mymELym

yBMgrid CAP

xEFCAPEF

,

,,,

,,

CAPm,y: Incrementally installed capacity of power unit m in year y. The generation capacities for coal-fired, oil-fired and gas- fired technology are available for the calculation. However; there are multi-fuel fired capacity additions utilizing solid+liquid fuel or liquid+natural gas fuel mixtures. Therefore; first the fuel consumption data are used to calculate the proportion of CO2 emissions from each fossil fuel type. Second, the emission factors for the best commercially available technology of power generation for each fossil fuel are calculated. Third, the emission factor for thermal power is calculated as a weighted average of all emission factors calculated in the Step 1. Finally, this thermal emission factor is multiplied by the proportion of thermal power added capacity in the additional 20% capacity. Sub-step 6(a) Calculate the percentages of CO2 emissions from each type of fossil fuel-fired power plants in total CO2 emissions from all thermal power plants. According to the methodology; the ratio of tCO2 produced by each fossil fuel type for power generation is calculated with the following formulas:

∑

∑=

yiiyiyi

yiyiyi

i EFNCVF

EFNCVF

,,,

,,

**

**

λ

λi : Ratio of CO2 produced by fossil fuel i to the total emissions.

Fi,y : Amount of fuel i consumed by power sources in year y [kt or m3]

NCVi,y : Net calorific value for fossil fuel i in year y [TJ/kt]

EFi : CO2 emission factor of fuel type i used in power sources in (tCO2/TJ)

j : Power units included in the build margin y : Most recent historical year for which power generation data is available

Sub-step 6(b) Calculating fossil fuel fired emission factor (EFThermal)

First the emission factors for the best commercially available technology are calculated:

EFi,Adv= EFi,j x Max(Efficiencyi)

EFi,Adv : Emission factors with efficiency levels of the best commercially available technology in Turkey (tCO2/MWh).


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EFi : CO2 emission factor of fuel type i (tCO2/TJ)

Max(Efficiencyi,y) : Maximum of the efficiency values calculated for fuel type i

Then thermal emission factor is calculated with the formula:

∑=i AdviiThermal EFEF ,*λ

EFThermal : Weighted emissions factor of thermal power generation with the efficiency level of the best commercially available technology in Turkey (tCO2/MWh). λi : Ratio of CO2 produced by fossil fuel i to the total emissions.

EFi,Adv : Emission factors with efficiency levels of the best commercially available technology in Turkey (tCO2/MWh). Sub-step 6(c) Calculating Build Margin Emission Factor

ThermalTotal

ThermalyBMgrid EF

CAP

CAPEF *,, =

EFgrid,BM,y : Build Margin CO2 emission factor in year y (tCO2/MWh). CAP Thermal: Total thermal power capacity addition of the selected period [MW]

CAPTotal : Total power capacity addition of the selected period [MW]

EFThermal : Emission factors with efficiency levels of the best commercially available technology in Turkey (tCO2/MWh). Step7. Calculate the combined margin emission factor The combined margin emissions factor EFgrid,CM,y is calculated as follows: EFgrid, CM, y=EFgrid,OMsimple,y *wOM +EFgrid,BM,y *wBM EFgrid, BM, y : Build margin CO2 emission factor in year y (tCO2/MWh) EF grid,OMsimple,y : Operating margin CO2 emission factor in year y (tCO2/MWh) wOM :Weighting of operating margin emissions factor (%) wBM :Weighting of build margin emissions factor (%) The combined margin emissions factor EFgrid,CM,y should be calculated as the weighted average of the Operating Margin emission factor (EFgrid,OMsimple,y) and the Build Margin emission factor (EFgrid,BM,y), where wOM = 0.5 and wBM = 0.5 for hydropower project for the first crediting period and for subsequent crediting periods. 3.2 Project Emissions

According to the methodology, the project emissions are estimated on the basis of the power density of the project activity (PD) which is calculated as follows:

BLPJ

BLPJ

AA

CapCapPD

−−=

Where: PD : Power density of the project activity (W/m2)


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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. The power density of the proposed project is 101.91 x106W/1,889,000 m2= 54 W/ m2. The referred methodology the project emissions for hydro power plants with a power density greater than 10 W/m2 is taken as zero. 3.3 Leakage

According to the ACM0002 version 12.2.0, leakage should be considered if the energy generating equipment is transferred from another activity. The proposed project is a new power plant and therefore the leakage is taken as zero. 3.4 Summary of GHG Emission Reductions and Removals

Calculation of Operating Margin The following data are available on the Turkish Electricity Transmission Company (TEĐAŞ) web site: • Annual fuel consumption by fuel type (tons or m3)39, • Annual heating values for fuels consumed for electricity generation (Tcal)40 • Annual electricity generation by fuel type, import and export (GWh)41 Annual heating values for each fuel type are directly related with the fuel consumption and are used to calculate Net Calorific Values (TJ/kt) for each year (Table.14). The annual heating values are converted to TJ and divided by the fossil fuel consumption for that year. Table.14. Net Calorific Values for each fuel type for Turkey. Fuel Type NCV

(TJ/kt)

2007 2008 2009

Hard Coal + Imported Coal 22.30 22.24 22.21 Lignite 6.86 6.83 6.43 Fuel Oil 39.87 39.70 39.81 Diesel Oil 43.09 42.38 42.37 LPG - - 46.47 Naphtha 43.18 44.61 43.65 Natural Gas 36.76 36.63 37.17 The coefficients required for calculation of CO2 emission factor (tCO2/TJ) have been obtained through IPCC 2006 guidelines for GHG inventories42. Using the available data and the formula given in section B6.1, overall CO2 production by electricity generation is calculated as given in Table.15. below.

39( http://www.teias.gov.tr/istatistik2008/44.xls) 40 (http://www.teias.gov.tr/istatistik2008/46.xls) 41( http://www.teias.gov.tr/istatistik2008/30(84-08).xls)&( http://www.teias.gov.tr/istatistik2008/37(06-08).xls) 42 Table 2.2.Default Emission Factors for Stationary Combustion in the Energy Industries, Vol.2. Energy, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, (http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf)


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Table.15. Calculation of total emission by electricity generation

COEF (tCO2/TJ) (Lower)

Fuel Consumption (2007-2009)

(tons or 1000m3)

Total Emission (2007- 2009)

(tCO2) Hard Coal+ Imported Coal 94.600 18,920,328 39,826,848.54

Lignite 90.933 191,218,459 116,533,083.19

Fuel Oil 67.833 6,018,378 18,081,399.61

Diesel Oil 72.600 362,296 1,117,127.87

LPG 61.6 111 317.74

Naphtha 69.300 30,124 91,453.49

Natural Gas 54.267 63,043,468 126,165,678.56

Total Emissions 301,815,909.00

Net electricity generated and supplied to the grid by thermal plants has been calculated using data obtained from the TEĐAŞ web page43. The ratio between gross and net generation has been calculated first, and assuming that the same ratio is valid for thermal plants; gross generation by thermal power plants has been multiplied by this ratio in order to find net generation by thermal plants. Summing up this with the imported electricity, total supply excluding low cost / must run sources are determined as given in Table.16. below.

Table.16. Net Electricity Generation from thermal power plants (units in GWh)

Year Gross generation

Net generation

Net/Gross (1)

Gross Gen. Thermal

(2)

Net Gen Thermal

(1x2) Import

Total Supply to the grid

2007 191,558.1 183,339.7 0.957 155,196.2 148,537.8 864.3 149,402 2008 198,418.0 189,761.9 0.956 164,139.3 156,978.6 789.4 157,768 2009 194812.9 186619.3 0.958 156,923.4 150,323.4 812.0 151,135 Total 455839.8 2,466 458305.5

Finally, using the data tabulated in the previous two tables, the OM emission factor considering years 2007 -2009 has been calculated as generation weighted average from equation for OM above;

EFgrid, OMsimple, y = 0, 659 tCO2/ MWh The Operating Margin emission factor calculated above will be constant throughout the 7 years crediting period. Calculation of Build Margin Sub-step 6(a) Calculate the percentages of CO2 emissions from each type of fossil fuel-fired power plants in total CO2 emissions from all thermal power plants. The annual fuel consumption data for each fuel type for 2003-2009 are gathered from TEIAS web page. Net calorific value (in TJ/kt) are calculated as described above for the same period. The lower values for CO2 emission coefficient (tCO2/TJ) from IPCC 2006 guidelines for GHG inventories have been used. The following ratios have been obtained:

43 Annual Development of Electricity Generation-Consumption and Losses in Turkey (http://www.teias.gov.tr/istatistik2008/30(84-08).xls)


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Table.17. Ratio of CO2 by each fossil fuel type to the total emissions

Fuel Type λi Fuel Type λi

Coal 0.125 Lpg 0.00016

Lignite 0.380 Naphta 0.004

Fuel Oil 0.083 Natural Gas 0.405

Diesel Oil 0.003

Sub-step 6(b) Calculate the operating margin emission factor of fuel-based generation. The thermal efficiency values for each fossil fuel type are directly calculated from heating values and annual electricity generation data of the period 2002-2009 by using the annual heating values and electricity generation data. The maximum efficiency values are taken for the sake of conservativeness (Table.18).

Table.18. Average of calculated thermal efficiency factors Fossil fuel type Efficiency (%) Coal 42.89 Lignite 37.55 Fuel-oil 30.05 Diesel-oil 23.11 LPG 31.14 Naphtha 36.75 Natural gas 48.72

EF Thermal is calculated as 0.674 tCO2/MWh Sub-step 6(c) Calculating Build Margin Emission Factor The Build Margin has been calculated as 0.533 tCO2/MWh. Calculation of the Combined Margin EFgrid, CM, y = 0.5 * 0.659 + 0.5 * 0.533 = 0.596 The combined margin emission factor is therefore 0.596 tCO2/MWh, which will be used as the baseline factor in calculation of emission reduction by project activity. Please see the detailed data for emission reduction calculations in Annex.1. Quantifying GHG emissions and/or removals for the project: According to ACM0002 version 12.2.0, leakage emission only have to be considered if the energy generating equipment is transferred from another activity or if the existing equipment is transferred to another activity. Since this is not the case, leakage is thus considered as null: LEy= 0. The Project Emissions have to be considered in the case of the power density of the hydro power plant is between 4 W/m2 and 10W/m2. Provided that the power density of the project is 54 W/ m2, Project Emissions are: PEy= 0.


v3.0 37

Thus: PEy+LEy = 0. Emission reduction (ERy) by the proposed project activity is calculated for the first crediting period of ten years by the following formula:

Where: ERy: Emission reductions achieved by the project activity in year y (tCO2e). BEy: Baseline Emission in year y (tCO2e). PEy: Project Emission in year y (tCO2e). LEy: Leakage Emissions in year y (tCO2e). ERy= (281,191 MWh * 0.596) +(30,572*0.596)-(0+0) = 167,590 + 18,221 =185,811 tCO2 The total emission reduction will be 185,811 tCO2

Table.19. Estimated emission and removals

Years Estimated baseline emissions or removals (tCO2e)

Sarıgüzel HEPP

Estimated baseline emissions or removals (tCO2e)

Sarıgüzel-1 HEPP

Estimated project emissions or removals (tCO2e)

Estimated leakage emissions (tCO2e)

Estimated net GHG emission reductions or removals (tCO2e)

01.04.2013 125,692 13,666 0 0 139,358

2014 185,811167,590 18,221 0 0 185,811

2015 167,590185,811 18,221 0 0 185,811

2016 167,590185,811 18,221 0 0 185,811

2017 167,590185,811 18,221 0 0 185,811

2018 167,590185,811 18,221 0 0 185,811

2019 167,590185,811 18,221 0 0 185,811

2020 167,590185,811 18,221 0 0 185,811

2021 167,590185,811 18,221 0 0 185,811

2022 167,590185,811 18,221 0 0 185,811

01.04.2023 41,898 4,555 0 0 46,453

Total 1,675,900 182,210 0 0 1,858,110

ERy = BEy − (PEy + LEy)


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4 MONITORING

4.1 Data and Parameters Available at Validation

Data Unit / Parameter: Electricity generation

Data unit: MWh

Description: Total electricity generated by all power plants connected to the national grid including low-cost must run power plants between 2002-2009.

Source of data: TEIAS (Turkish Electricity Transmission Company) annual data

Value applied: Detailed in Annex.1

Justification of choice of data or description of measurement methods and procedures applied:

Official data

Any comment:

Data Unit / Parameter: EGy

Data unit: MWh

Description: Net electricity generated by all power plants connected to the national grid excluding low-cost must run power plants between 2007-2009.




Official data

Any comment:

Data Unit / Parameter: Electricity imported

Data unit: MWh

Description: Electricity imported to the national grid between 2007-2009.




Official data

Any comment:

Data Unit / Parameter: FC

Data unit: Tonnes/m3


v3.0 39

Description: Fossil fuel consumed by thermal power plants between 2002-2009




Official data

Any comment:

Data Unit / Parameter: NCV

Data unit: TJ/mass or volume

Description: Net calorific value of each fossil fuel type between 2002-2009




Official data

Any comment:

Data Unit / Parameter: EFCO2

Data unit: tCO2/TJ

Description: Net calorific value of each fossil fuel type between 2002-2009

Source of data: 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 Inventories



Official data

Any comment:

Data Unit / Parameter: ηm,y

Data unit: -

Description: Average net energy conversion efficiency of thermal power units connected to the grid

Source of data: Calculated by TEIAS (Turkish Electricity Transmission Company) annual data


v3.0 40



Official data

Any comment:

Data Unit / Parameter: Capacity addition

Data unit: MWh

Description: Capacity addition to the national grid between 2002-2009




Official data

Any comment:

Data Unit / Parameter: EFRes

Data unit: kgCO2/MWh

Description: Default emission factor for emissions from reservoirs

Source of data: Decision by EB23

Value applied: 90 kgCO2e/MWh


Official data.

Any comment:

Data Unit / Parameter: PD

Data unit: W/m2

Description: Power density

Source of data: Project feasibility study, Nov 2010

Value applied: 54 W/m2


Official data, Feasibility report is approved by State Hydraulic Works.

Any comment:


v3.0 41

4.2 Data and Parameters Monitored

Data Unit / Parameter: EGBLy

Data unit: MWh/yr

Description: Net electricity exported to the grid in the year y

Source of data: Monthly official electricity metering reports issued by governmental officers and signed by both parties.

Description of measurement methods and procedures to be applied:

The net electricity is measured continuously by a power meter at the grid interface and recorded monthly.

Frequency of monitoring/recording: Monthly

Value applied: The annual electricity fed to the grid is estimated as 311,763 MWh.

Monitoring equipment: Power meters should be in line with Measure and Metering Devices Regulation44 and with IEC-EN 60687 Standards with the accuracy class 0.5S.

QA/QC procedures to be applied: • A spare meter is used for crosschecking the accuracy and both meters are calibrated if required.

• Data measured by meters and will be crosschecked with the the data collected by the internal SCADA system.

• The accuracy class for the power meters is 0.5S and calibrated once in ten years.

Calculation method: N/A Any comment:

4.3 Description of the Monitoring Plan

The Monitoring Plan is based on version 12.2.0 of the approved methodology ACM0002. In order to calculate the annual emission reduction by the project, net electricity fed by the project to the grid will be monitored. Purpose of monitoring The objective of the monitoring plan is to ensure the complete, consistent, clear, and accurate monitoring and calculation of the emissions reductions during the whole crediting period. The Project Owner is responsible for the implementation of the monitoring plan. Monitoring parameters According to the methodology applied, the electricity supplied to the national grid by the proposed project and the electricity consumed by the project activity shall be monitored. The net electricity is the difference of the electricity supplied and consumed by the project and shall be taken into account for emission reduction calculations.

44 http://www.mevzuat.adalet.gov.tr/html/21179.html


v3.0 42

Monitoring Organization and System The organizational chart is attached to Annex. 5 and explained as follows:

• Operational staff will be selected from a pool of experts serving to all Kandil Energy Group Projects.

• Two operational technicians will be in charge working on site in three shifts every day.

• Two mechanical technicians will join to operational technicians in daily shifts.

• All technicians will report to Operation Leader.

• Operational staff will be working on control desk in three shifts and will report to Operation Leader.

• Operations Director is responsible from operations of all Kandil Energy Group projects.

• Hydro Group Manager is supported by Health Safety Emergency &Workplace Health team, department assistant and administrative staff. He reports to Operations Director.

• Maintenance team supports all Kandil Energy Group Projects; one of the Maintenance Engineers will be responsible of the team. Maintenance Responsible reports to Hydro Group Manager.

• Maintenance leader is supported by Maintenance Supervisors for technical and mechanical maintenance. The supervisor team for mechanical maintenance is composed of 6 mechanical technicians and the team for electrical maintenance is composed of 2 electrical technician and 2 Instrumentation & Control technicians.

• Maintenance Leader reports to the Maintenance Responsible.

The Project Owner will be responsible for the overall management of the monitoring procedures including recording, data collection, calculating emission reductions and project emissions. Monthly power meter readings will be basis for monitoring net electricity fed into the grid. Those readings are done by governmental officers (Turkish Electricity Transmission Company-TEIAS) accompanied with an observer from the project owner company at the end of each month. A report is prepared including day, peak and night hour electricity generation of the plant and signed and approved by both parties. The gross electricity generated and internal consumption by the proposed project will be monitored and recorded hourly by the internal Supervisory Control and Data Acquisition System (SCADA). The gross electricity generated does not comprise the energy losses through transformer before electricity fed into the national grid. Therefore, subtracting the internal consumption from the gross generation the project owner will cross-check the data presented in the monthly power meter reading reports. Data Management and Quality Control Two power meters will be installed at the grid interface of the proposed project. One will be the main meter and the other will be back-up meter of the main meter for cross-checking. Both meters are jointly inspected and sealed in order to be protected from interference by any of the parties. The electrical diagram is presented in Annex.3. The main and spare meter readings are recorded in kWhs monthly and cross-checked whether calibration is required. The capacity of the transmission line connected is 154 kVA, the accuracy class for power meters


v3.0 43

have been defined in the Communiqué for Power Meters45 as 0.2S class. The calibration will be implemented in accordance with the related standard procedures (IEC-EN 60687). The periodical maintenance is under the responsibility of TEIAS and has been fixed as once in 10 years in accordance with Article.9 of Measure and Metering Devices Regulation46. When the main meter has a breakdown, the readings of the back-up meter will be used. If both meters failed, conservative data substitution procedures based on the internal SCADA data will be used. All data collected as part of monitoring will be archived electronically by the project owner and be kept at least for 2 years after the end of the last crediting period. Description of the monitoring plan Monitoring Plan will be implemented by the following steps: 1) The electricity generated will be metered by two power meters placed at the point of connection to national grid. 2) The official data will be read and recorded monthly by TEIAS officers for invoicing. The data include net electricity exported to the grid. 3) The official data will be cross-checked by the hourly gross electricity generation measured and recorded by the internal SCADA system in the powerhouse. 4) The emission reductions will be calculated by multiplying the net electricity with the CM calculated below. In case calibration required for the two power meters during the crediting period, the official report will be provided by the Project Owner.

5 ENVIRONMENTAL IMPACT

The Environmental Impact Assesment was completed on June 2007 and affirmative decision has been taken for the project on 11/06/2007 by Ministry of Environment and Forestry (MoEF) (Annex.2.). The project affects only a small portion of the livelihoods since most (57 percent) households lose less than 25 percent of their land haoldings within the affected communities. The project will not result in physical displacement and no household will be relocated as a result of land acquisition. On the overall, the impacts can be considered as minor. An overview of the impacts from land acquisition is as follows:

• Most land needed for the Project belongs to the Forest Department (67%) • A total of 340 parcels of land is required for the Sarıgüzel Dam and HEPPs; of these 302 parcels

belong to private households, and 38 parcels belong to the Treasury; • The average number of parcel per affected households is 1.6, with minimum 1 and maximum 7

parcels per household; • The number of households affected is limited to 16 percent of the total number of households in the

affected communities; • One hundred eighty (180) households will lose a portion of their land, crops, trees and different

physical structures as a result of land acquisition required for the project; of these 180 households, only one will lose its residential building. However, this household will not be relocated because the building is used as a second home;

• A total of 124 households were interviewed out of the 180 affected households. Surveyed households owned on average 1.9 ha of land and lost 0.5 ha to the project (i.e. 23 percent of their land holdings). Of these 124 households, fifty seven (57) percent of the affected households lose less than 25 percent of their land holding; 28 percent of he affected households lose 26-50 percent of

45 http://www.epdk.gov.tr/mevzuat/teblig/elektrik/sayac/sayacson.doc 46 http://www.mevzuat.adalet.gov.tr/html/21179.html


v3.0 44

their land. Those losing 51-75 percent constituted 7 percent of the affected households and 8 percent lose over 76 percent of their holdings47.

The forest land in material site and reservoir will be cleared from vegetation. In return of the vegetation loss, trees and plant species appropriate for the region will be planted during landscaping after construction. The plan for the soil conservation will be implemented for the farmland. Medium level of erosion is observed on the site. After the commissioning of the project, the land subject to erosion will be planted. The reservoir area will be re-organized to from recreational areas. Excavation will be done for preparation of the site for construction and explosions will also take place during the construction of diversion and energy tunnels. The vegetated top soil excavated will be collected separately and will be re-used for gardening and green areas. The excavated material is stored in specially arranged storage areas. The materials suitable for construction will be used as concrete aggregate. The explosions will be done under the control of gendarme and the local residents will be informed about the place and time of the explosions. The nearest settlement to the site where explosions will take place is Dömüler district which is 1,000 m away. No serious impacts are foreseen for the buildings. Quarry area within the project site will be used to supply concrete aggregate for the construction of dam body. The material will be supplied from an area of 64.61 hectares. A crunching-sieving-washing facility will be located on the project site for the production of concrete aggregate. Hacınınoğlu Weir and HPP will also benefit from the materials obtained from the site. Dust emissions will occur from excavation, explosions, crunching-sieving-washing facility, loading and unloading of excavated material and the movement of heavy construction machines. Topographical structure of the region will prevent the dust dispersion. The residential areas Tilkiler District and Hacınınoğlu Village will be affected mostly from dust emission but it will be below the daily allowed limits according to the modelling done for the worst case scenario during EIA studies. Noise level caused by the construction activities will be below the allowed limits (70dBA) in the residential areas. However, Đkizler District at 225m distance to transmission tunnel and Tilkiler district where the tunnel will go underneath will be affected from vibration. In order to mitigate those impacts, a land survey will be done before the construction starts. In accordance with the study done, the explosions will be done in smaller steps and the houses identified to be affected will be expropriated. The route of riverbed will be diverted temporarily during construction. This may have an adverse effect on the river ecosystem and water quality. In order to mitigate those adverse impacts, the natural flow regime of the river has been evaluated. According to Montana Method, which accounts 20% of annual daily flow to be released to the river, a flow rate of 11.74 m3/sec would be appropriate for the continuation of the biological life downstream during the operational phase. The method advises to release 10% of the same amount for temporary cases. Therefore; the flow rate will 5.87 m3/sec for the construction phase. In order to avoid negative impacts on water quality, the vegetation in the reservoir area will be cleared before impoundment. The water used for crunching-sieving-washing facility will be supplied form Ceyhan River, will be treated in settlement tanks and discharged back to the river. Domestic wastewater generated at the camp site and construction site is first settled in impermeable septic tanks and then treated in package wastewater treatment plant. The treated wastewater is recollected in impermeable septic tank and after reaching to sufficient amount, sucked by the sewage trucks of Kahramanmaraş Municipality. The recyclable solid waste such as iron pieces, plate, packing material and etc. will be collected separately and domestic solid waste will be collected by Kahramanmaraş Municipality. Domestic solid wastes are collected at the bins placed at the camp site and stored at the solid waste disposal area. Solid waste collected is transferred to the solid waste disposal site of Kahramanmaraş Municipality.

47 Plese see Resettlement Action Plan for the project (http://www.enerjisa.com.tr/files/SRG_RAP_Report.pdf)


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A third party consultant does monitoring activities for the environmental commitments and prepares reports in every 3 months. In addition, official reports are prepared and submitted to MoEF biannually. The monitoring report includes studies for ambient air quality, noise measurement, water quality monitoring and disposal of domestic solid waste, wastewater and hazardous waste. The project is also controlled by Enerjisa’s onsite environmental team. The project follows environmental and social standards of International Finance Corporation (Performance Standards, Equator Principles) and audited by Finance Institutions from time to time as well.

6 STAKEHOLDER COMMENTS

The nearest residential areas which would be affected from the project are Sarıgüzel Village, Kertmen Village and Hacınınoğlu Village. A formal meeting with the related governmental institutions, including Regional Directorate of State Hydraulic Works, Special Provincial Administration, Provincial Directorate of ministry of Public Works and Settlement, Provincial Gendarme; are held in Kahramanmaraş Provincial Department Environment and Forestry. The officers were informed about the project and their questions are answered. The stakeholders meeting has been organized for the participation of local community to environmental impact assessment in Đkizce Primary School in Sarıgüzel Village on 26/12/2006. The meeting has been announced in one local and one national newspaper and Mukhtars of the villages to be affected by the project are invited. 87 participants attended the meeting. The public was informed about the project and their opinions and suggestion were asked under the presidency of Kahramanmaraş Provincial Department Environment and Forestry. It has been observed that the local community was concerned about the expropriation process and possible impacts on the houses in Tilkiler District where the transmission tunnel will go underneath. The project owners explained that the expropriation process will be in line with the laws and regulations and will be in a way that the local community would not be mistreated. It is also explained that a land survey will be done in Tilkiler District before the construction of transmission tunnel starts and then the houses identified to be affected will be expropriated. The project owner added that the bridges, canals and other required infrastructure which will be submerged under reservoir will be re-built and they will priority to the local residents during hiring.


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Figure.8. Participation of local community The local community was confirmed about the explanations and their perception of the project was positive as most of the necessary services and equipment for the project will be provided from locality and therefore will vitalize the domestic economy.


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Annex.1. Baseline Information

Data Used in calculation of OM for Turkish Electricity Grid Table.A. Heating Values of Fuels Consumed in Thermal Power Plants in Turkey by the Electric Utilities (Tcal)48 Years 2007 2008 2009

Hard Coal Imported Coal

32,115 33,310 35,130

Lignite 100,320 108,227 97,652

Total 132,435 141,537 132,781 Fuel Oil 21,434 20,607 15,160 Diesel Oil 517 1,328 1,830 Naphta 118 113 84 TOTAL 22,069 22,048 17,076 Natural Gas 179,634 189,057 186,266 TOTAL 334,138 352,642 336,123

Table.B. Fuel Consumed in Thermal Power Plants in Turkey by the Electric Utilities (ton /m3)49 Years 2007 2008 2009

Hard Coal Imported Coal

6,029,143 6,270,008 6,621,177 Lignite 61,223,821 66,374,120 63,620,518 TOTAL 67,252,964 72,644,128 70,241,695 Fuel Oil 2,250,686 2,173,371 1,594,321 Diesel Oil 50,233 131,206 180,857 Lpg 0 0 111 Naphta 11,441 10,606 8,077 TOTAL 2,312,360 2,315,183 1,783,366 Natural Gas 20,457,793 21,607,635 20,978,040 Table.C. Net Electricity supply to the grid by thermal plants and imports50

Year Gross generation

Net generation Import

2007 191,558.1 183,339.7 864.3

2008 198,418.0 189,761.9 789.4

48 http://www.teias.gov.tr/istatistik2009/46.xls 49 http://www.teias.gov.tr/istatistik2009/44.xls 50 http://www.teias.gov.tr/istatistik2009/30(84-09).xls


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2009 194812.9 186619.3 812.0 Table.D. Default Emission Factors for Stationary Combustion in the Energy Industries (kg of greenhouse gas per TJ on a Net Calorific Basis)51

Fuel CO2

Default Emission Factor

Lower Upper

Residual Fuel Oil 77,400 75,500 78,800 Gas/Diesel Oil 74,100 72,600 74,800 Residual Fuel Oil 77,400 75,500 78,800 Liquefied Petroleum Gases

63,100 61,600 65,600

Naptha 73,300 69,300 76,300 Anthracite 98,300 94,600 101,000 Lignite 101,000 90,900 115,000 Natural Gas 56,100 54,300 58,300

Data Used in calculation of BM for Turkish Electricity Grid

Calculation of l Efficiency Table.E. Heating values of fuels consumed in thermal power plants in Turkey by electric utilities (Tcal)52,53

Fuel 2002 2003 2004 2005 2006 2007 2008 2009 Hard Coal 5,565 5,297 4,790 5,551 29,504 32,115 33,310 35,130 Imported Coal 3,057 13,316 19,728 20,984 Lignite 75,923 63,607 61,018 68,513 83,932 100,320 108,227 97,652 Total 84,545 82,220 85,536 95,048 113,436 132,435 141,537 132,781 Fuel Oil 30,500 27,444 22,926 19,263 16,769 21,434 20,607 15,160 Diesel Oil 1,007 146 295 291 627 517 1,328 1,830 Lpg 105 8 139 142 0 0 0 1 Naphta 2,353 2,527 2,197 895 141 118 113 84 TOTAL 33,965 30,125 25,557 20,591 17,537 22,069 22,048 17,076 Natural Gas 100,716 112,044 117,464 140,350 150,588 179,634 189,057 186,266 TOTAL 219,226 224,389 228,557 255,989 281,561 334,138 352,642 336,123

Table.F. Annual development of Turkey’s electricity generation by primary energy sources (GWh)54

YEARS Hard Coal

+Imported coal Lignite Fuel-Oil Diesel Oil LPG Naphtha Natural Gas

51 Table 1.4 (http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_1_Ch1_Introduction.pdf) 52 http://www.teias.gov.tr/istatistik2009/45.xls 53 http://www.teias.gov.tr/istatistik2009/46.xls 54 http://www.teias.gov.tr/istatistik2009/32(75-09).xls


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2002 4,093.1 28,056.0 9,505.0 270.9 34.8 933.1 52,496.5

2003 8,663.0 23,589.9 8,152.7 4.4 2.9 1,036.2 63,536.0

2004 11,998.1 22,449.5 6,689.9 7.3 33.4 939.7 62,241.8

2005 13,246.2 29,946.3 5,120.7 2.5 33.7 325.6 73,444.9

2006 14,216.6 32,432.9 4,232.4 57.7 0.1 50.2 80,691.2

2007 15,136.2 38,294.7 6,469.6 13.3 0.0 43.9 95,024.8

2008 15,857.5 41,858.1 7,208.6 266.3 0.0 43.6 98,685.3 2009 16,595.6 39,089.5 4,439.8 345.8 0.4 17.6 96,094.7

Calculation of BM: Table.G. Annual development of Turkey’s installed capacity (MW)55

YEARS Thermal Hydro Geothermal Wind Capacity Add. TOTAL 2002 19,568.5 12,240.9 17.5 18.9 31,845.8

2003 22,974.4 12,578.7 15.0 18.9 3,741.2 35,587.0

2004 24,144.7 12,645.4 15.0 18.9 1,237.0 36,824.0

2005 25,902.3 12,906.1 15.0 20.1 2,019.5 38,843.5

2006 27,420.2 13,062.7 81.9 - 1,721.3 40,564.8

2007 27,271.6 13,394.9 169.2 270.9 40,835.7

2008 27,595.0 13,828.7 29.8 363.7 981.5 41,817.2

2009 29,339.1 14,553.3 77.2 791.6 2,944.0 44,761.2

Annex.2. Affirmative EIA decision

55

http://www.teias.gov.tr/istatistik2009/3.xls


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According to the article 14 of the Regulation on Environmental Impact Assessment that is issued in 16 December 2003, “Environmental Impact Assessment is affirmative” decision is given for “Sarıgüzel Dam, HEPP and Quarries” project.


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Annex.3. Single Line Diagram


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Annex.4. Hydropower Plants, Private Sector (2009)

No Name

Installed Capacity

(MW)

Annual Generation

(GWh)

Firm Generation

(GWh)

1 BEREKET (DENĐZLĐ) 3,7 12 12

2 AKÇAY 28,8 95 45

3 ANADOLU ÇAKIRLAR 16,2 60 28

4 CEYKAR BAĞIŞLI 29,6 99 47

5 BEREKET ( DALAMAN) 37,5 179 179

6 BEREKET (FESLEK) 9,5 41 25

7 BEREKET (GÖKYAR) 11,6 43 23

8 BEREKET (MENTAŞ) 39,9 163 140

9 BEREKET (KOYULHĐSAR) 42,0 329 155

10 BEYOBASI (SIRMA) 5,9 23 11

11 AKUA KAYALIK 5,8 39 20

12 AKKÖY ENERJĐ (AKKÖY I HES) 101,9 408 263

13 ALP ELEKTRĐK (TINAZTEPE) 7,7 29 17

14 CANSU ELEKTRĐK (ARTVĐN) 9,2 47 31

15 CĐNDERE DENĐZLĐ 19,1 58 30

16 ÇALDERE ELEKTRĐK (DALAMAN) 8,7 35 25

17 DAREN HES (SEYRANTEPE BARAJI) 49,7 182 161

18 DEĞĐRMENÜSTÜ (KAHRAMANMARAŞ) 38,6 106 52

19 DENĐZLĐ EGE 1 0,9 4 2

20 EKĐN ENERJĐ (BAŞARAN HES) 0,6 5 0

21 ELESTAŞ YAYLABEL 5,1 20 10

22 ELESTAŞ YAZI 1,1 6 3

23 ENERJĐ-SA BĐRKAPILI 48,5 171 17

24 ENERJĐ-SA-AKSU-ŞAHMALLAR 14,0 45 7

25 ENERJĐ SA-SUGÖZÜ-KIZILDÜZ 15,4 55 8

26 EŞEN-II (GÖLTAŞ) 43,4 170 80

27 ELTA (DODURGA) 4,1 12 12

28 ERVA KABACA HES 8,5 33 15

29 FĐLYOS YALNIZCA HES 14,4 67 33

30 HAMZALI HES (TURKON MNG ELEK.) 16,7 117 66

31 H.G.M.ENER.(KEKLĐCEK HES) 8,7 18 11

32 HĐDRO KONTROL YUKARI MANAHOZ 22,4 79 45

33 ĐÇ-EN ELEK. ÇALKIŞLA 7,7 18 11

34 ĐÇTAŞ YUKARI MERCAN 14,2 44 20

35 ĐSKUR (SÜLEYMANLI HES) 4,6 18 4

36 KALEN ENER. (KALEN I-II) 31,3 104 47

37 KAREL (PAMUKOVA) 9,3 55,0 40,0

38 KAYEN KALETEPE HES 10,2 37 17


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39 KURTEKS (Karasu Andırın HES) 2,4 19 19

40 TGT EN. LAMAS III-IV 35,7 150 71

41 MARAŞ ENERJĐ (FIRNIS) 7,2 36 23

42 MOLU ENERJĐ (BAHÇELĐK HES) 4,2 30 30

43 MURGUL BAKIR 4,6 8 8

44 ÖZGÜR ELEKTR.K.Maraş Tahta HES 12,5 54 54

45 ÖZGÜR ELEKTR.AZMAK II 24,4 91 43

46 ÖZTAY GÜNAYŞE 8,3 29 14

47 ÖZYAKUT GÜNEŞLĐ HES 1,8 8 4

48 PAMUK (Toroslar) 23,3 112 28

49 SARMAŞIK I HES (FETAŞ FETHĐYE ENERJĐ) 21,0 96 54

50 SARMAŞIK II HES (FETAŞ FETHĐYE ENERJĐ) 21,6 108 61

51 SARITEPE HES DĐNAMĐK 4,9 20 9

52 SU ENERJĐ (ÇAYGÖREN HES) 4,6 19 4

53 ŞĐRĐKÇĐOĞLU KOZAK 4,4 15 7

54 TAŞOVA YENĐDEREKÖY 2,0 10 6

55 TEMSA ELEKTRĐK (GÖZEDE HES) 2,4 10 6

56 TEKTUĞ-KARGILIK 23,9 83 19

57 TEKTUĞ-KALEALTI HES 15,0 52 11

58 TEKTUĞ-KEBENDERESĐ 5,0 32 20

59 TEKTUĞ-ERKENEK 12,5 50 30

60 TURKON MNG REŞADĐYE III 22,3 175 88

61 UZUNÇAYIR 27,3 105 49

62 YEŞĐL ENERJĐ (TAYFUN HES) 0,8 5 4

63 YEŞĐLBAŞ 14,0 56 26

64 YAPISAN HACILAR DARENDE 13,3 90 54

65 YAPISAN KARICA DARICA 97,0 328 154

66 YPM ALTINTEPE SUŞEHRĐ HES 4,0 18 10

67 YPM BEYPINAR HES 3,6 18 9

68 YPM KONAK HES 4,0 19 10

69 YPM GÖLOVA 1,1 3 2

70 YPM SEVĐNDĐK 5,7 36 18

71 YURT EN. TOCAK I 4,8 13 6

72 TÜM EN. PINAR 30,1 138 65

73 BEYKÖY ZORLU 16,8 87 87

74 KUZGUN ZORLU 20,9 36 0

75 TERCAN ZORLU 15,0 51 28

76 ATAKÖY ZORLU 5,5 8 8

77 ÇILDIR ZORLU 15,4 30 20

78 ĐKĐZDERE ZORLU 18,6 110 100

79 MERCAN ZORLU 20,4 78 48

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Annex.5. Organizational Chart

PROJECT DESCRIPTION

Organizational Chart


54

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