(GS) Other

Transkript

(GS) Other

UNFCCC/CCNUCC
CDM – Executive Board
Page 1
PROJECT DESIGN DOCUMENT FORM
FOR CDM PROJECT ACTIVITIES (F-CDM-PDD)
Version 04.1
PROJECT DESIGN DOCUMENT (PDD)
Title of the project activity
Version number of the PDD
Completion date of the PDD
Project participant(s)
Host Party(ies)
Sectoral scope and selected methodology(ies)
Estimated amount of annual average GHG
emission reductions
Aksu Wind Farm Project, Turkey
1.0
30/04/2013
Aksu Temiz Enerji Elektrik Uretim Sanayi ve
Ticaret A. S. (private entity)
Turkey
Scope number : 1
Sectoral scope : Energy industries (renewable
- / non-renewable sources)
Methodology: “ACM0002: Consolidated
baseline methodology for grid-connected
electricity generation from renewable sources -- Version 13.0.0”
118,737 tCO2-eq
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SECTION A. Description of project activity
A.1. Purpose and general description of project activity
Basic Description:
Aksu Wind Farm Project, Turkey (Hereafter referred to as “The Project”) is a large scale wind farm
project located in Yahyalı District, Kayseri Province of Turkey. The Project is owned by Aksu Temiz
Enerji Elektrik Uretim Sanayi ve Ticaret A. S. (Hereafter referred to as “The Project Proponent”), a
private entity.
Technical Description:
The installed capacity of the project is 72 MW, and the project involves installation and operation of 36
wind turbines, each having a rated power output of 2 MW. The turbines will be of Vestas brand, V1002.0MW model, and IEC IIIA class. The diameter of the area swept by the blades will be 100 meters and
the hub height will be 80 meters. The output voltage of each turbine will be 690 VAC, and this will be
stepped up to medium voltage at 33.6 kV. This voltage will again be increased by a power transformer to
high voltage at 154 kV and the wind farm will be connected to Camlica-I HEPP substation at this 154 kV
level as a single group via an overhead transmission line and from this point the energy will be fed to the
national grid.
The estimated annual net electricity generation of the project will be about 194,003 MWh. This electrical
energy will replace electrical energy of the national grid, based mainly on various fossil fuel sources like
natural gas and coal. The expected annual emission reduction to be caused by the project will be around
118,737 tonnes of CO2e. For a 7-year crediting period the expected emission reductions will be about
825,899 tonnes of CO2e. The operation of the project and electricity generation started in 2012 and the
expected operational life of the project is 20 years.
Description of sources and gases included in the project boundary:
Baseline Emission Sources included in the project boundary are the generation mix of the national grid
whose CO2 emissions are displaced due to the project activity. Project Activity Emission Sources
included in the project boundary are those sources emitting gases and particulate matters during
construction and operation of the project activity. However, these are minor sources with emissions of
very small amounts; so their emissions are neglected and they are excluded. Only CO 2 is included as the
gas whose emissions and/or emission reductions will be taken into account due to the project activity.
1) The purpose of the project activity:
The purpose of the project activity is to generate renewable electrical energy utilising wind as the
primary energy source and deliver this energy to the national grid of Turkey. This energy will help
supply Turkey’s ever-increasing electricity demand through a clean, sustainable, and reliable technology.
The project will displace the same amount of electricity that would otherwise be generated by the fossil
fired power plants dominating the national grid.
Being the first operational wind farm in Kayseri Province, the project will help renewable energy
become more widespread in Turkey.
1.a. The scenario existing prior to the start of the implementation of the project activity:
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The scenario existing prior to the start of the implementation of the project activity was no electricity
generation since the project is a greenfield project. Without the implementation of the project, the same
amount of energy would be generated by other power plants of the national grid. Considering the
general fossil fuel domination in the national grid, a natural gas or coal fired thermal power plant on
average would generate this energy. This imaginary power plant would also emit greenhouse gases
including CO2 and particulate matters. Since the project will emit no greenhouse gases within its
boundary and no leakage is in question, an emission caused by the net electricity generation displaced by
the project activity was produced prior to the implementation of the project.
1.b. The project scenario:
The project scenario involves implementation of a wind farm utilising wind as the primary energy
source to generate electrical energy and delivery of the generated electricity to the national grid. 36 wind
turbines, a high voltage overhead transmission line, a switchyard, an administrative and control building
and other necessary minor structures will be installed within the proposed project activity. Necessary
measures have been and will be taken during both in the constructional and operational phases of the
project in order not to cause any harmful impact on environmental, economical and social structure of
the region. All the related legislation and regulations are observed. In addition, the project proponent
will make contributions to the sustainable development of the region.
1.c. The baseline scenario:
The baseline scenario is the same as the scenario existing prior to the start of implementation of the
project activity.
2) Greenhouse gas emission reduction mechanism of the proposed project activity:
The project activity will reduce greenhouse gas emissions as reference to the baseline scenario taking
into account that it is a zero emission project. No greenhouse gas or particulate matter emission will take
place within project boundary and no leakage emissions will occur. Hence, a net emission reduction
from the baseline emission level to zero level will result with the energy generated by the project that will
displace the energy that would otherwise be generated by the fossil fuel fired power plants in the
national grid. Although many harmful gases including the greenhouse gases and particulate matters will
be avoided by the emission reduction process, only CO 2 will be considered in the emission reduction.
3) The view of the project participants (The Project Proponent) on the contribution of the project
activity to sustainable development:
The project activity will result in many positive impacts on the sustainable development of the region.
Environment:
The electricity produced by the project activity will replace the electricity that would otherwise have been
produced by the generation mix of the grid that is mainly composed of fossil fuel fired power plants like
natural gas and coal. With the replacement of this energy and resultant avoidance of fossil fuel
consumption, not only CO2 emission will be prevented, but the emission of other greenhouse and
various harmful gases and particulate matters will also not occur. As a result, the negative impacts of
these pollutants will be reduced.
During constructional phase of the project activity, roads to the project site area and the power plant
itself on the project site area will be built. Mainly some few amount of dust emission will take place
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during the construction. Other emissions are negligible. Maximum effort will be shown to keep this dust
emission as low as possible and all the related national regulations will be observed.
Most of the project site area is agricultural fields owned by the inhabitants from the surrounding villages.
The project developer made a commitment to solve this problem in an optimal way to satisfy the land
owners. Real estate easement agreements were made with land owners to lease the lands for the licence
period of the power plant, which is 49 years. So, this issue can be assumed as having been mitigated and
solved. The land owners will be able to use parts of their lands that are not used by the wind farm
structures within technical limits for agricultural purposes. Landscape arrangements will be made to keep
the impact on project site area as low as possible as compared to its original form.
Social development
The jobs that will be created by the project activity will be high quality jobs requiring professional skills
and training. Furthermore, the personnel to be employed in the project will be trained on subjects like
occupational health and safety, first aid and fire protection. As a result, employment quality will be
increased in the region as compared to the baseline in which more ordinary jobs not requiring
professional skills and training would be produced, if any.
The Project Proponent intends to make a positive contribution to the livelihood of the poor in the
region. In this respect, local people and local authorities and representatives were consulted and their
related needs and requests were questioned. As a result, the project proponent undertook the
construction of a community health centre built in Dikme Village, the nearest settlement to the project
site. This community health centre will ease the access to health care services in the region compared to
the baseline.
Economical and technological development:
Economically, the main positive effect will be on quantitative employment and income generation. Local
people will be given priority when employing new personnel for the wind farm depending on their
qualifications and professional skills. This will cause an increase in employment quantity and income in
the region as compared to the baseline scenario. Without the project, no jobs at all or jobs with lower
quality with lower incomes would be generated in the baseline scenario.
The project activity will be the first operational wind farm in Kayseri Province. Kayseri Province is an
industrially developed part of the Central Anatolian Region of Turkey and had been the only private
distribution region of Turkey for a long time before the widespread privatization in electricity
distributions of Turkey began. Implementation of the project activity will enhance wind power
technology especially in local level. Technological improvements, research and development and
production of auxiliary equipment related with wind power technology will be enhanced with the
implementation of the project activity.
A.2. Location of project activity
A.2.1. Host Party(ies)
The host party is Turkey.
A.2.2. Region/State/Province etc.
Central Anatolian Region / Kayseri Province / Yahyalı District
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A.2.3. City/Town/Community etc.
The project site is about 35 km away from Yahyalı District Centre, near Dikme Village. Other nearby
villages are Karaköy, Delialiuşağı and Avlağa. The nearest turbine to the Dikme Village is about 600
meters away.
A.2.4. Physical/Geographical location
Location of the project is given in the following figure including the maps of the project region and the
turbine layout and the table giving the final coordinates of the individual turbines.
(a)
(b)
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(c)
Figure 1. Maps showing the project location and layout of the turbines. (a) Project location in Turkey.
(b) Project location in Central Anatolian Region and Kayseri Province. (c) Layout of the turbines near
Dikme Village in the project site area.
Table 1. Final turbine coordinates of the project
Final Turbine Coordinates of Aksu Wind Farm, Turkey
UTM ED50 Coordinates, UTM Zone: 36S
Turbine
Turbine
E
N
Number
Number
T01
723,049 4,210,172 T19
T02
723,287 4,210,230 T20
T03
723,532 4,210,248 T21
T04
724,990 4,210,224 T22
T05
725,248 4,210,078 T23
T06
725,482 4,209,884 T24
T07
725,807 4,210,010 T25
T08
726,622 4,209,482 T26
T09
726,387 4,209,676 T27
T10
726,182 4,209,449 T28
T11
725,881 4,209,423 T29
T12
725,596 4,209,393 T30
T13
725,355 4,209,539 T31
T14
725,040 4,209,526 T32
T15
724,733 4,209,433 T33
T16
724,418 4,209,321 T34
T17
723,957 4,209,038 T35
E
N
723,249
723,183
722,853
722,485
722,243
721,912
721,685
721,329
721,193
721,028
720,778
720,987
721,276
721,508
724,323
721,968
722,232
4,208,636
4,209,170
4,209,031
4,209,313
4,209,382
4,209,196
4,209,327
4,209,407
4,209,226
4,209,071
4,209,029
4,208,519
4,208,567
4,208,573
4,208,677
4,208,471
4,208,313
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T18
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721,739 4,208,579 T36
724,707 4,210,397
A.3. Technologies and/or measures
The project activity involves electricity generation from renewable energy sources utilising wind energy
as the primary energy source. Wind power is one of the main renewable energy sources used in the
world for electricity generation.
Turkey’s electricity generation mainly depends on fossil fuel fired power plants. Natural gas and coal are
the main fossil fuels used in the power plants.1 Although the share of power plants using renewable
energy sources is increasing in the recent years, most of these are hydro power plants and the wind
power plants still constitute a very small percentage of the national installed capacity. 2,3,4
In the absence of the project, the same amount of electricity would be generated by a hypothetical
thermal power plant representing the fossil fuel dominated character of the national grid. This power
plant would have most probably been a natural gas coal fired plant. This power plant would cause GHG
emissions, mainly CO2 emissions. The project will cause no GHG emissions. Hence, the project will
reduce all the emissions that would take place in its absence.
The project is a greenfield project, therefore no other project would be developed in its absence. The
baseline scenario and the scenario existing prior to the start of the implementation of the project activity
is the same and corresponds to a situation in which the same energy would be generated by the national
grid causing GHG emissions.
In the scope of the project, 36 wind turbines each having a 2 MW output power will be installed along
with auxiliary structures including switchyard, administrative and control buildings, etc. The main
components of the turbines include blades, hub, nose cone, nacelle, rotor, gearbox, generator, braking
and yaw systems, tower, control systems, etc. among many others. Turbine specifications are
summarised in the table below:
Table 2. Specifications of Vestas V100-2.0 MW wind turbine
Component
/
Explanation / Value
Specification
Brand
Vestas
Model
V100 – 2.0 MW
Class
IEC IIIA
Rated Power
2000 kW
Number of blades
3 (Horizontal axis)
Rotor diameter
100 m
Rotor swept area
7,854 m2
Hub height
80 m
Cut-in Wind Speed
3.0 m/s
Rated Wind Speed
12.5 m/s
Cut-out Wind Speed
20 m/s
Recut-in Wind Speed
18 m/s
1
Fuels Consumed In Thermal Power Plants In Turkey By The Electricity Utilities (2006-2011)
(http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2011/yakıt46-49/47.xls)
2
TEIAS Installed Capacity Data of Turkey (http://www.teias.gov.tr/yukdagitim/kuruluguc.xls) (Accessed on 22 January 2013)
3
http://www.yegm.gov.tr/yenilenebilir/document/kuruluguc.xls
4
Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021).
(http://www.teias.gov.tr/KapasiteProjeksiyonuARALIK2012.pdf)
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Load Factor
Generator Efficiency
Average Lifetime
Page 8
% 37.2
% 97
20 years
The output voltage of each turbine will be 690 VAC, and this will be stepped up to medium voltage at
33.6 kV. The turbines will be collected in two groups each consisting of 18 turbines and having 36 MW
capacities. Each group will be connected to a 154/33.6 kV 50-62.5 MVA transformer and the voltage will
again be increased to high voltage at 154 kV. The wind farm will then be connected to Camlica-I HEPP
substation at this 154 kV level as a single group via a 12 km long overhead transmission line. From this
point on the energy will be fed to the national interconnected grid.
Regarding the way how the technologies and measures and know-how to be used in the project are
transferred to host party (Turkey), it can be said that the development of the project will most likely
cause a positive impact on technological innovation and technology transfer in the region. Although
main parts of the project including the turbines and the control system have been exported from abroad,
many electrical parts including transformers, switchyard equipment, cabling instruments and most of the
constructional material have been supplied from domestic sources. Also, construction work which is
specific to wind power technology has been performed by a domestic company.
Kayseri Province is a special region that has a unique status in the electricity distribution system of
Turkey. Up until recently, Kayseri and Vicinity Electricity Turkish Incorporated Company (KCETAS),
the company responsible for the electricity distribution of Kayseri Province, had been the only private
electricity distribution company of Turkey5. Kayseri is one of the most developed provinces of Turkey
with respect to industry and trade6. However, there had been no wind farms in Kayseri Province until the
commissioning of Aksu Wind Farm, even though the fact that several licenses have been granted to
various companies by Energy Market Regulatory Authority (EPDK)7.
Aksu Wind Farm became the first operational wind farm in Kayseri Province. This is also true for
surrounding provinces8. Although wind power technology is not new in Turkey, most of the wind farms
are concentrated in Aegean, Marmara and to a lesser extent some parts of Mediterranean Geographical
Regions of Turkey. Due to these reasons, it will very likely enhance technological innovation,
technology and know-how transfer and technological self-reliance in the region consisting of Kayseri
and surrounding provinces.
A.4. Parties and project participants
The Project Proponent is the only project participant. The project participant is listed in the following
table, and the contact information of the project participant is provided in Annex 1.
5
http://www.kcetas.com.tr/?kanal=tarihce
http://www.kayserito.org.tr/media/Kayseri_Ekonomisinin_Turkiyedeki_Yeri.pdf
7
http://lisans.epdk.org.tr/epvys-web/faces/pages/lisans/elektrikUretim/elektrikUretimOzetSorgula.xhtml
http://www2.epdk.org.tr/data/index.htm
http://www2.epdk.org.tr/data/EPDSantral/kayseri.pdf
8
http://www2.epdk.org.tr/data/index.htm
6
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Table 3. Parties and Project Participants involved in the Project
Party involved
(host) indicates a host Party
Turkey (host)
Private and/or public
entity(ies) project participants
(as applicable)
Indicate if the Party involved
wishes to be considered as
project participant (Yes/No)
Aksu Temiz Enerji Elektrik
Uretim Sanayi ve Ticaret A. S.
(private entity)
No
The Project Proponent, Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A. S., is the owner and
developer of the project.
The Republic of Turkey is the host country. Turkey ratified the Kyoto Protocol on 28 May 2009 and the
protocol entered into force on 26 August 2009. However, Turkey is a party for which Party for which
there is a specific COP and/or CMP decision; and although being an Annex I Country, it has no
commitments under Kyoto Protocol. National focal point of Turkey for UNFCCC is the Ministry of
Environment and Urban Planning. Regional Environmental Centre Country Office Turkey (REC Turkey)
acts as the National Focal Point for UNFCCC Article 6 – Education, Training and Public Awareness.
A.5. Public funding of project activity
No public funding from Parties included in Annex 1 or Official Development Assistance (ODA) is
involved for the project activity.
SECTION B. Application of selected approved baseline and monitoring methodology
B.1. Reference of methodology
The approved baseline and monitoring methodology applied to the project activity is “ACM0002:
Consolidated baseline methodology for grid-connected electricity generation from renewable sources --Version 13.0.0”.
Tools referenced in this methodology:
1. Tool for the demonstration and assessment of additionality
2. Combined tool to identify the baseline scenario and demonstrate additionality
3. Tool to calculate project or leakage CO2 emissions from fossil fuel combustion
4. Tool to calculate the emission factor for an electricity system
Only two of these tools, “Tool to calculate the emission factor for an electricity system (Version 03.0.0)”
for baseline emission calculation and “Tool for the demonstration and assessment of additionality
(Version 07.0.0)“ for the assessment of additionality are used.
Since no project emission or leakage is in question regarding the project activity, “Tool to calculate
project or leakage CO2 emissions from fossil fuel combustion” is not used. “Combined tool to identify
the baseline scenario and demonstrate additionality” is also not used since it is not applicable to the
project according to the scope and rules defined therein.
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B.2. Applicability of methodology
The choice of methodology ACM0002 and related tools are justified based on the fact that the proposed
project activity meets the relevant applicability conditions of the chosen methodology and tools:





The project is a greenfield project. No power plant or a similar facility had been present in the
project site when the project activity began.
The project is a grid-connected renewable power generation project.
The project activity does not involve any capacity addition or any retrofit or replacement of an
existing power plant.
The project activity is the installation of a wind power plant.
There is no project emission or leakage related with the project activity.
B.3. Project boundary
The project utilises wind as the primary energy source to generate electricity. During normal operation
when enough wind is present to generate wind, the project activity draws no energy from the grid to
meet its auxiliary electricity consumption need. The project meets its auxiliary electricity consumption
need from its own generated electricity. When there is not sufficient wind to generate electricity, the
project will draw some electricity from the grid to use for auxiliary electricity consumption. There is a
backup power generator using diesel fuel to be used only when power cannot be supplied from the grid
due to a connection loss, grid maintenance, or a power outage in the grid. Under only very such rare
occasions will the backup power generator operate and produce emissions. These emissions are
expected to be very low and can be neglected; so assumed to be zero.
Apart from the backup diesel power generator, there is no equipment or machinery related with the
project activity that can produce any emissions.
Table 4. Emission sources and GHGs included or excluded in the project boundary
Project scenario
Baseline scenario
Source
Electricity
generation mix
of national grid
displaced by
project activity
Activities
during
constructional
and operational
phases of the
project
GHG
s
CO2
Yes
CH4
N2O
Other
No
No
No
CO2
CH4
N2O
Other
No
No
No
No
Included?
Justification/Explanation
Major GHG emission from the power plants in the
fossil-fuel dominated national grid in the absence of
the project activity is CO2. The amount of other
gases and pollutants are very low compared to CO 2.
So, CO2 is included in the baseline emission
calculation.
Although there may be CH4 or N2O emissions from
the power plants in the grid during electricity
generation in the absence of the project activity,
these emissions would be very low and trivial as
compared to CO2. As a result, CH4 or N2O emissions
in the baseline emission calculations are neglected
and assumed as zero.
Under normal conditions, no CO 2, CH4 or N2O
emissions will occur apart from normal domestic
activities of the personnel like heating and cooking.
And those emissions resulting from these domestic
activities will be very low to be taken into account in
the calculations. So, these are neglected and not
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included.
The wind turbines in the project activity are divided into two groups for which there are separate power
transformers and metering systems. There are 21 turbines in Group 1, namely Turbines no. 4, 5, 6, 7, 8,
9, 10, 11, 12, 13, 14, 15, 16, 17, 19, 20, 21, 22, 23, 33 and 36. There are 15 turbines in Group 2, namely
Turbines no. 1, 2, 3, 18, 24, 25, 26, 27, 28, 29, 30, 31, 32, 34 and 35.
The flow diagram of the project boundary with its connections to the national grid is shown in the
following figure. The monitoring variable used for emission reduction calculations is the net amount of
generated electricity measured by two monitoring systems consisting of main and backup electricity
meters for each group.
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Figure 2. Schematic diagram showing the flow diagram of the project boundary, its connection to
national grid, and emission sources and gases included in the project boundary and monitoring
variables.
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B.4. Establishment and description of baseline scenario
The selected baseline methodology for the development of PDD is “ACM0002: Consolidated baseline
methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0”. So,
the most plausible baseline scenario is identified in accordance with this methodology.
Baseline methodology procedure explained on pages 4 – 5 of this methodology proposes three
alternatives for identification of the baseline scenario. Since the project activity is the installation of a
new grid-connected wind power plant with 36 turbines and is not a capacity addition to or the retrofit or
replacement for an existing grid-connected renewable power plant, the first alternative is the most
suitable one for the project for identification of the baseline scenario; which is explained as follows9:
“If the project activity is the installation of a new grid-connected renewable power plant/unit, the
baseline scenario is the following:

“Electricity delivered to the grid by the project activity would have otherwise been generated
by the operation of grid-connected power plants and by the addition of new generation
sources, as reflected in the combined margin (CM) calculations described in the “Tool to
calculate the emission factor for an electricity system”.”
Since the project activity has nothing to do with a capacity addition or the retrofit or replacement of an
existing grid-connected renewable power plant/unit(s) at the project site, the other two alternative
scenarios and respective step-wise procedures are not applicable.
This assumption of baseline scenario can also be justified and supported by data, statistics and studies
performed by TEIAS (Turkish Electricity Transmission Corporation).
The following two tables summarize the situation of Turkish Electricity Generation sector as at the end
of 2011:
Table 5. Distribution of Total Installed Capacity of Turkey by Fuel / Energy Source Types as at the end
of 20112, 4.
THE END OF 2011
FUEL TYPES
FUEL-OIL + ASPHALTITE + NAPHTA + DIESEL
OIL
IMPORTED COAL + HARD COAL + LIGNITE
NATURAL GAS + LNG
RENEWABLE + WASTE
MULTI-FUEL SOLID + LIQUID
MULTI-FUEL LIQUID + N. GAS
GEOTHERMAL
HYDRAULIC DAMMED
9
INSTALLED
CAPACITY
(MW)
CONTRIBUTION
(%)
NUMBER OF
POWER
PLANTS
1,362.3
2.6
23
12,355.7
16,004.9
115.4
556.5
3,536.4
114.2
13,529.3
23.4
30.2
0.2
1.1
6.7
0.2
25.6
24
155
18
8
52
7
58
ACM0002: Consolidated baseline methodology for grid-connected electricity generation from renewable sources --- Version
13.0.0, page 4. (http://cdm.unfccc.int/UserManagement/FileStorage/DYPFI935XBG274NWH6O8CM1KEZR0VU)
UNFCCC/CCNUCC
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3,607.7
1,728.7
6.8
3.3
251
47
52,911.1
100.0
643
HYDRAULIC RUN-OF-RIVER
WIND
TOTAL
Table 6. Distribution of Gross Electricity Generation of Turkey by Fuel / Energy Source Types in 201110
THE DISTRIBUTION OF GROSS ELECTRICITY GENERATION BY
PRIMARY ENERGY RESOURCES IN TURKEY
2011
Energy
(GWh)
PRIMARY ENERGY RESOURCES
COAL
Hard coal+Imported Coal+Asphaltite
Lignite
COAL TOTAL
Fuel Oil
Diesel Oil
LPG
Naphtha
LIQUID TOTAL
LIQUID FUELS
27,347.5
38,870.4
66,217.9
900.5
3.1
0.0
0.0
903.6
104,047.6
469.2
171,638.3
52,338.6
694.3
4,723.9
229,395.1
Natural Gas
Renewables and Wastes
THERMAL TOTAL
HYDRO
GEOTHERMAL
WIND
GENERAL TOTAL
Share
(%)
11.92
16.94
28.87
0.39
0.00
0.00
0.00
0.39
45.36
0.205
74.82
22.82
0.30
2.06
100.00
TEIAS publishes annual capacity projection reports to forecast the future possible situation of Turkish
Electricity Sector based on current available data. These projections are performed assuming two
different scenarios, one with a high demand assumption, and the other with a low demand assumption.
The development of total firm energy generation capacity of Turkish grid for a 10 year period (2012 –
2021) for these two scenarios according to the latest Capacity Projection Report (2012) are as follows:
Table 7. Development of Total Firm Generation Capacity by Energy Resource Types11
(Scenario 1 – High Demand)
(Operational, with State Owned Power Plants Under Construction and Private Sector Owned
Power Plants Under Construction Granted by Licence and Expected to be in Service on
Proposed Date) (Projects Granted by Licence with an Indefinite Date of Commissioning
Excluded)
(a) Generation (GWh)
YEARS
LİGNITE
HARD COAL +
10
11
2011
34973
3738
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
34984
3738
44118
3857
48600
3857
52676
4829
56651
5801
56748
5801
57260
5801
57260
5801
57260
5801
57260
5801
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2011/uretim%20tuketim(22-45)/44.xls
Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021), p. 53.
UNFCCC/CCNUCC
Page 15
ASPHALTİTE
IMPORTED COAL
NATURAL GAS
GEOTHERMAL
FUEL OIL
DIESEL OIL
NUCLEAR
OTHERS
THERMAL TOTAL
BIOGAS + WASTE
HYDRAULIC
WIND
25461
134625
802
6805
148
0
1408
207959
804
53317
5002
25461
141708
802
6805
148
0
1408
215053
945
56661
5180
25426
145475
912
9034
148
0
1408
230376
1111
44940
5764
25002
150184
1212
9034
148
0
1408
239443
1166
48717
6907
29474
162289
1402
9034
148
0
1408
261259
1196
54932
7644
36481
167216
1402
9034
148
0
1408
278139
1196
62536
7644
38272
167848
1402
9034
148
0
1408
280659
1196
67210
7644
38311
168184
1402
9034
148
0
1408
281547
1196
68946
7644
38311
168184
1402
9034
148
4200
1408
285747
1196
69386
7644
38311
168184
1402
9034
148
12600
1408
294147
1196
69386
7644
38311
168184
1402
9034
148
21000
1408
302547
1196
69386
7644
TOTAL
267081
277840
282192
296234
325031
349516
356709
359334
363974
372374
380774
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
(b) Percentage (%)
YEARS
2011
LİGNITE
HARD COAL +
ASPHALTİTE
IMPORTED COAL
NATURAL GAS
GEOTHERMAL
FUEL OIL
DIESEL OIL
NUCLEAR
OTHERS
BIOGAS + WASTE
HYDRAULIC
WIND
13,1
12,6
15,6
16,4
16,2
16,2
15,9
15,9
15,7
15,4
15,0
1,4
1,3
1,4
1,3
1,5
1,7
1,6
1,6
1,6
1,6
1,5
9,5
50,4
0,3
2,5
0,1
0,0
0,5
0,3
20,0
1,9
9,2
51,0
0,3
2,4
0,1
0,0
0,5
0,3
20,4
1,9
9,0
51,6
0,3
3,2
0,1
0,0
0,5
0,4
15,9
2,0
8,4
50,7
0,4
3,0
0,0
0,0
0,5
0,4
16,4
2,3
9,1
49,9
0,4
2,8
0,0
0,0
0,4
0,4
16,9
2,4
10,4
47,8
0,4
2,6
0,0
0,0
0,4
0,3
17,9
2,2
10,7
47,1
0,4
2,5
0,0
0,0
0,4
0,3
18,8
2,1
10,7
46,8
0,4
2,5
0,0
0,0
0,4
0,3
19,2
2,1
10,5
46,2
0,4
2,5
0,0
1,2
0,4
0,3
19,1
2,1
10,3
45,2
0,4
2,4
0,0
3,4
0,4
0,3
18,6
2,1
10,1
44,2
0,4
2,4
0,0
5,5
0,4
0,3
18,2
2,0
TOTAL
100
100
100
100
100
100
100
100
100
100
100
Table 8. Development of Total Firm Generation Capacity by Energy Resource Types 12
(Scenario 2 – Low Demand)
(Operational, with State Owned Power Plants Under Construction and Private Sector Owned
Power Plants Under Construction Granted by Licence and Expected to be in Service on
Proposed Date) (Projects Granted by Licence with an Indefinite Date of Commissioning
Excluded)
(a) Generation (GWh)
YEARS
LİGNITE
HARD COAL +
ASPHALTİTE
IMPORTED COAL
NATURAL GAS
GEOTHERMAL
FUEL OIL
DIESEL OIL
NUCLEAR
OTHERS
THERMAL TOTAL
12
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
34973
34976
44109
48600
49714
51964
53298
53810
53810
53810
53810
3738
3738
3857
3857
4829
5801
5801
5801
5801
5801
5801
25461
134625
802
6805
148
0
1408
207959
25461
140423
802
6805
148
0
1408
213760
25426
143243
912
9034
148
0
1408
228137
25002
148138
1057
9034
148
0
1408
237243
25214
160616
1247
9034
148
0
1408
252208
27961
166641
1402
9034
148
0
1408
264357
29752
167848
1402
9034
148
0
1408
268689
34051
168184
1402
9034
148
0
1408
273837
38311
168184
1402
9034
148
4200
1408
282297
38311
168184
1402
9034
148
12600
1408
290697
38311
168184
1402
9034
148
21000
1408
299097
Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021), p. 60.
UNFCCC/CCNUCC
BIOGAS + WASTE
HYDRAULIC
WIND
TOTAL
Page 16
804
53317
5002
872
55923
5108
1038
43676
5602
1166
46966
6462
1196
51459
7288
1196
58052
7644
1196
63771
7644
1196
67744
7644
1196
69386
7644
1196
69386
7644
1196
69386
7644
267081
275663
278453
291837
312151
331249
341300
350421
360524
368924
377324
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
(b) Percentage (%)
YEARS
2011
LİGNITE
HARD COAL +
ASPHALTİTE
IMPORTED COAL
NATURAL GAS
GEOTHERMAL
FUEL OIL
DIESEL OIL
NUCLEAR
OTHERS
BIOGAS + WASTE
HYDRAULIC
WIND
13,1
12,7
15,8
16,7
15,9
15,7
15,6
15,4
14,9
14,6
14,3
1,4
1,4
1,4
1,3
1,5
1,8
1,7
1,7
1,6
1,6
1,5
9,5
50,4
0,3
2,5
0,1
0,0
0,5
0,3
20,0
1,9
9,2
50,9
0,3
2,5
0,1
0,0
0,5
0,3
20,3
1,9
9,1
51,4
0,3
3,2
0,1
0,0
0,5
0,4
15,7
2,0
8,6
50,8
0,4
3,1
0,1
0,0
0,5
0,4
16,1
2,2
8,1
51,5
0,4
2,9
0,0
0,0
0,5
0,4
16,5
2,3
8,4
50,3
0,4
2,7
0,0
0,0
0,4
0,4
17,5
2,3
8,7
49,2
0,4
2,6
0,0
0,0
0,4
0,4
18,7
2,2
9,7
48,0
0,4
2,6
0,0
0,0
0,4
0,3
19,3
2,2
10,6
46,7
0,4
2,5
0,0
1,2
0,4
0,3
19,2
2,1
10,4
45,6
0,4
2,4
0,0
3,4
0,4
0,3
18,8
2,1
10,2
44,6
0,4
2,4
0,0
5,6
0,4
0,3
18,4
2,0
TOTAL
100
100
100
100
100
100
100
100
100
100
100
As can be seen from the data depicted in the tables, the current thermal dominated nature of Turkish
Electricity Generation Sector is not expected to change within the next ten years significantly. This
conclusion justifies the assumption that the baseline scenario is the case in which the electricity delivered
to the grid by the project activity would have otherwise been generated by the operation of newly added
grid-connected power plants and would correspond to the continuation of current energy resource
distribution situation of the national grid.
Although a special feed-in-tariff and incentives are given to power plants using renewable energy
sources according to Law on Utilization of Renewable Energy Resources for the Purpose of Generating
Electrical Energy13 (Law No: 5346, Issuance Date: 18.05.2005), this supportive mechanism does not seem
to change the future probable situation of electricity generation sector in a distinguishable way. So, the
assumption of baseline scenario is still valid in the presence of the feed-in-tariff and incentives included
in this law.
B.5. Demonstration of additionality
B.5.1. Implementation Timeline of the Project Activity
An overview of Implementation timeline of the project activity can be found in the table below:
Table 9. Implementation timeline of the project activity
Activity
Initial Issuance of Generation Licence
EIA not required certificate
Transfer of majority shares (70 %) to Ayen Enerji A. S.
13
Date
29/11/2007
03/11/2009
14/01/2011
http://www.enerji.gov.tr/mevzuat/5346/5346_Sayili_Yenilenebilir_Enerji_Kaynaklarinin_Elektrik_Enerjisi_Uretimi_Amacli_Kullani
mina_Iliskin_Kanun.pdf
http://www.epdk.gov.tr/documents/elektrik/mevzuat/kanun/Elk_Kanun_Yek_Kanun.doc
UNFCCC/CCNUCC
Approval of transfer of shares by EMRA (Energy Market
Regulatory Authority)
Submission of Financial Feasibility Report and EIA Report to
creditor bank (TSKB=Turkish Industrial Development Bank),
both including and providing evidence that the incentive from
CDM (Gold Standard VER) was seriously considered in the
decision to proceed with the project activity.
Turbine purchase and service agreement with turbine supplier
(Vestas)
Credit agreement with creditor bank (TSKB=Turkish Industrial
Development Bank)
Local Stakeholder Meeting
Start of construction works
First Partial Commissioning (18 Turbines) (Turbines No. 1, 2, 3,
4, 5, 6, 7, 9, 10, 11, 12, 13, 14, 15, 16, 17, 33, 36)
Second Partial Commissioning (15 Turbines) (Turbines No. 18,
19, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 34, 35)
Third and the Last Partial Commissioning (3 Turbines) (Turbines
No. 8, 20, 21)
Page 17
09/02/2011
07/04/2011
02/05/2011
27/05/2011
16/06/2011
19/07/2011
16/03/2012
05/04/2012
09/06/2012
As can be seen from the implementation timeline of the project, the revenues from VER credits had been
taken into account before electromechanical equipment order agreement and credit agreement. VER
revenues are considered in the financial analysis performed for investment. Financial Feasibility Report
submitted to the creditor bank for credit assessment included VER revenues and the creditor bank took
VER revenues into account when giving the credit. Environmental Impact Assessment Report also
mentioned VER revenues.
B.5.2. Assessment and Demonstration of Additionality
The selected baseline methodology for the development of PDD, “ACM0002: Consolidated baseline
methodology for grid-connected electricity generation from renewable sources --- Version 13.0.0” refers
to the latest version of the “Tool for the demonstration and assessment of additionality” (Version 07.0.0)
(referred to as “The Tool” hereafter in this section) for the demonstration and assessment of the
additionality. The methodology procedure of this tool defines a step-wise approach to be applied for the
project activity. The application of this step-wise approach to the proposed project activity is as follows:
Step 1: Identification of alternatives to the project activity consistent with current laws and regulations
Realistic and credible alternatives to the project activity are defined through the following sub-steps as
per the Tool:
Sub-step 1a: Define alternatives to the project activity:
Probable realistic and credible alternatives that may be available to the Project Proponent are assessed in
the following alternate scenarios:
a) The proposed project activity undertaken without being registered as a CDM (GS VER) project
activity
This alternative would be realistic and credible if the project proponent had found the project financially
feasible as a result of investment analysis. But the investment analysis showed that the project is not
UNFCCC/CCNUCC
Page 18
financially feasible without the incentive coming from the GS VER revenues. So the project is not
considered as credible and feasible by the project proponent although it may be realistic without being
registered as a CDM (GS VER) project activity.
(b) Other realistic and credible alternative scenario(s) to the proposed CDM project activity scenario
that deliver outputs services (e.g., cement) or services (e.g. electricity, heat) with comparable quality,
properties and application areas, taking into account, where relevant, examples of scenarios identified
in the underlying methodology;
The project activity is a power plant using renewable energy sources to generate electricity without
emitting any greenhouse gases. So, any other realistic and credible alternative scenario to the proposed
project activity scenario that delivers services (electricity) with comparable quality would be another
power plant utilising another renewable energy source to generate electricity without emitting any
greenhouse gases.
But, in the project area there are no other available renewable or non-renewable energy sources to be
used for electricity generation. Hence, there are no other realistic and credible alternative scenarios to the
proposed project activity that delivers electricity with comparable quality. Therefore, this alternative is
not realistic or credible.
(c) If applicable, continuation of the current situation (no project activity or other alternatives
undertaken).
The investment decision for the project activity depends on financial feasibility analysis and risk
assessment performed by the project proponent. If the financial feasibility analysis and risk assessment
had not been positive, the project would not have been realized. Hence, this scenario in which there
would be no project activity is a realistic and credible alternative scenario.
This scenario is the continuation of the current situation and corresponds to the case in which the same
amount of electricity would be generated by the existing national grid which is composed of a generation
mix largely depending on fossil fuels. This alternative is the same as baseline scenario in which the same
amount of electricity that would be delivered to the national grid by the project activity would have
otherwise been generated by the power plants connected to the national grid whose current composition
is mainly dependent on fossil fuels.
Outcome of Step 1a: As a result, the above alternatives (a) and (c) are identified as realistic alternative
scenarios, but only alternative (c) is found to be the credible alternative scenario to the project activity.
Sub-step 1b: Consistency with mandatory laws and regulations:
Both the above identified alternatives, whether they are realistic and credible or not are in compliance
with all mandatory applicable legal and regulatory requirements, among which the following are the
most important ones:
Table 10. Important mandatory laws and regulations that the project is consistent with
(a) Legislation about electricity generation and marketing:
Law / Regulation / Communiqué / Protocol
Electricity Market Law
Law on Utilization of Renewable
Number / Enforcement
Date
4628 / 03.03.2001
5346 / 18.05.2005
UNFCCC/CCNUCC
Energy Resources for the Purpose of Generating Electrical Energy
Energy Efficiency Law
Electricity Market Licence Regulation
Electricity Market Grid Regulation
Electricity Market Distribution Regulation
Regulation on Procedures and Principles as to Giving Renewable
Energy Source Certificate
Regulation on Certification and Support of Renewable Energy
Sources
Electricity Transmission System Supply Reliability and Quality
Regulation
Electrical Installations Project Regulation
Regulation on Technical Evaluation of Licence Applications based
on Wind Energy
Competition Regulation as to Licence Applications to Install
Generation Facility Based On Wind Energy
Protocol as to Establishment of Permission Procedures about Effects
of Wind Energy Power Plant Installation on Communication,
Navigation and Radar Systems
Regulation on Domestic Manufacturing of the Equipment Used in
Facilities Generating Electrical Energy from Renewable Energy
Sources
Regulation on Electrical Energy Demand Forecasts
Electricity Market Balancing and Settlement Regulation
Electricity Market Tariffs Regulation
Electricity Market Import and Export Regulation
Electricity Market Customer Services Regulation
Electricity Market Eligible Consumer Regulation
Electricity Market Ancillary Services Regulation
Communiqué on Connection to Transmission and Distribution
Systems and System Usage in the Electricity Market
Communiqué on Arrangement of Retail Contract in the Electricity
Market
Communiqué on Meters to be used in the Electricity Market
Communiqué on Wind and Solar Measurements
Communiqué on Procedures and Principles of Making Financial
Settlement in the Electricity Market
Page 19
5627 / 02.05.2007
- / 04.08.2002
- / 22.01.2003
- / 19.02.2003
- / 04.10.2005
- / 21.07.2011
- / 10.11.2004
- / 16.12.2009
- / 09.11.2008
- / 22.09.2010
- / 27.12.2010
- / 19.06.2011
- / 04.04.2006
- / 25.09.2002
- / 25.09.2002
- / 04.09.2002
- / 27.12.2008
- / 27.03.2003
- / 31.08.2003
- / 22.03.2003
- / 11.10.2002
- / 30.03.2003
(b) Legislation about environment, forestry, labour and social security:
Law / Regulation / Communiqué / Protocol
Environmental Law
Forestry Law
Labour Law
Construction Law
Law on Soil Conservation and Land Use
National Parks Law
Cultural and Natural Heritage Preservation Law
Animal Protection Law
Number / Enforcement
Date
2872 / 11.08.1983
6831 / 08.09.1956
4857 / 22.05.2003
3194 / 09.05.1985
5403 / 19.07.2005
2873 / 11.08.1983
2863 / 23.07.1983
5199 / 01.07.2004
UNFCCC/CCNUCC
Environmental Impact Assessment Regulation
Regulation on Environmental Planning
Regulation on Permissions and Licences that have to be taken
according to Environmental Law
Air Quality Assessment and Management Regulation
Environmental Auditing Regulation
Regulation on Environmental Agents and Environmental Consulting
Firms
Regulation on Assessment and Management of Environmental Noise
Regulation on Control of Waste Oils
Regulation on Amendment in the Regulation on Control of Waste
Oils
Regulation on diggings that will be done where it is not possible to
construct a sewage course
Regulation on Occupational Health and Safety
Noise Regulation
Vibration Regulation
Regulation on Machine Safety
Page 20
- / 17.07.2008
- / 11.11.2008
- / 29.04.2009
- / 06.06.2008
- / 22.09.2010
- / 12.11.2010
- / 04.06.2010
- / 30.07.2008
- / 30.03.2010
- / 19.03.1971
- / 09.12.2003
- / 23.12.2003
- / 23.12.2003
- / 05.06.2002
Outcome of Step 1b: All the alternatives to the project whether they are realistic and credible or not are
in compliance with all mandatory applicable and regulatory requirements.
Step 2: Investment analysis
The purpose of investment analysis is to determine whether the proposed project activity is not
(a) The most economically or financially attractive; or
(b) Economically or financially feasible, without the revenue from the sale of emission reductions.
To conduct the investment analysis, “Guidelines on the assessment of investment analysis” (Version
05.0) (referred to as “The Guidelines” hereafter in this section) has also been used apart from The Tool.
To conduct the investment analysis, stepwise approach of the Tool has been used.
Sub-step 2a: Determine appropriate analysis method
The Tool offers three alternative methods to conduct the investment analysis:
Option I
Option II
Option III
: Simple Cost Analysis
: Investment Comparison Analysis
: Benchmark Analysis
Since the project activity and the alternatives identified in Step 1 generate financial or economic benefits
by electricity sales, Option I (Simple Cost Analysis) cannot be applied.
To decide between Option II (Investment Comparison Analysis) and Option III (Benchmark Analysis),
Paragraph 19 of the Guidance (page 5) has been used. According to this clause, since the alternative to
the project activity is the supply of the electricity from the existing grid, Benchmark Analysis (Option
III) is considered appropriate.
UNFCCC/CCNUCC
Page 21
Sub-step 2b: Option III. Apply benchmark analysis
IRR (Internal Rate of Return) is identified as the most suitable financial/economic indicator for the
demonstration and assessment of additionality.
Equity IRR is selected as the IRR type to be used in the benchmark analysis. According to the
Guidelines, Required/expected returns on equity are appropriate benchmarks for an equity IRR. When
applying the benchmark analysis, the parameters that are standard in the market are used, according to
the Paragraph 37 of the Tool.
Sub-step 2c: Calculation and comparison of financial indicators (only applicable to Options II and
III):
A) Benchmark Rate Calculation
To find the benchmark rate, option (a) of the Paragraph 38 of the Tool is used:
“38. Discount rates and benchmarks shall be derived from:
(a) Government bond rates, increased by a suitable risk premium to reflect private investment and/or the
project type, as substantiated by an independent (financial) expert or documented by official publicly
available financial data;”
The benchmark rate is specified as the expected returns on equity (expected return on the capital asset /
cost of equity); and calculated using the Capital Asset Pricing Model (CAPM), as follows:
E(Ri) = Rf + βi (E(Rm) – Rf)
where:
E(Ri)
Rf
βi
: Expected returns on equity (Cost of Equity)
: Risk Free Return Rate in the Market (e.g. government bond yield)
: Beta Coefficient – Sensitivity of the Expected Returns to Market Returns
where
Rm
E(Rm) – Rf
i 
Cov(Ri , Rm )
Var ( Rm )
: Expected Return of the Market
: Market Risk Premium (the difference between the expected market rate of return and
the risk-free rate of return)
The assumptions and references for the calculation of the rates and coefficients above are explained
below:
i) Risk Free Rate (Rf)
As the representative of the risk free rate, Turkish Eurobond interest rates with the longest maturity (10
years) is chosen. EUROSTAT data for Turkey14 has been used to calculate this rate. The 5-year period of
14
http://epp.eurostat.ec.europa.eu/tgm/table.do?tab=table&init=1&plugin=1&language=en&pcode=tec00036
UNFCCC/CCNUCC
Page 22
[2007-2011] was assumed as the reference period. The arithmetic average of the annual averages for
these years was accepted as the government bond yield rate; hence the risk free rate. This value was
calculated as 13.51 %.
ii) Beta Coefficient (βi)
Beta Coefficient was calculated using the data available form Istanbul Stock Exchange15. Price Indices
for XU100-BIST100 (General) and XELKT-BIST ELECTRICITY (Electricity Generating and Trading
Companies) were collected and put into the relevant formula to calculate the Beta Coefficient. The value
of the Beta Coefficient was found to be 0.798. The details of the calculation can be found in the separate
spreadsheet file for the investment analysis supplied as an annex to PDD.
iii) Market Risk Premium (E(Rm) – Rf)
To assess the market risk premium of Turkey, the studies of Aswoth Damodaran, a well-known
independent researcher and an academician at the Stern School of Business at New York University,
were used 16. Country Risk Premiums for Turkey for the same 5-year reference period above ([20072011]) were taken and their arithmetic average was accepted as the market risk premium of Turkey as at
the end of 2011. The market risk premium value was found to be 10.09 %.
iv) Expected Returns on Equity (Cost of Equity) (E(Ri))
The expected returns on equity, the benchmark rate that would be used, was found, using the
calculations above, as:
E(Ri) = Rf + βi (E(Rm) – Rf) = 13.51 % + 0.798 * 10.09 % = 21.57 %
So, the benchmark discount rate to be used in the investment analysis is 21.57 %. This rate can be
assumed as reliable and conservative since it takes a period long enough (a five year period of [20072011]) as the reference and the beta coefficient takes all the companies in the electricity generation and
trading sector that are quoted in Istanbul Stock Exchange (the number was 5 at the end of 2011) into
account. The beta coefficient, hence the risk, for a single project of a single company is expected to be
higher than that of a value calculated for 5 companies for a period of 5 years.
A) Equity IRR Calculation for the Project
The following assumptions were made in calculating the Equity IRR for the project:
1) The VER revenues were calculated assuming a GS-VER credit unit price of 8.00 USD/tCO2-eq,
the average market value indicated for Turkey in the Ecosystem Marketplace State of the
Voluntary Carbon Markets 2012 Report17. This can be assumed as a fairly conservative price for
Turkish Wind Energy Projects, since it also takes all other projects, mostly hydro, and projects
developed under different standards, the price of which are generally lower than that of GS-VER
Wind Energy Projects.
15
http://borsaistanbul.com/en/-nbsp-data-nbsp-/data/equity-market-data/index-data
http://pages.stern.nyu.edu/~adamodar/New_Home_Page/data.html
17
Ecosystem Marketplace State of the Voluntary Carbon Markets 2012 Report, page 56.
(http://www.forest-trends.org/documents/files/doc_3164.pdf)
16
UNFCCC/CCNUCC
Page 23
2) The Energy Sales Unit Price was accepted as the guaranteed feed-in-tariff specified in the Law
on Utilization of Renewable Energy Resources for the Purpose of Generating Electrical Energy
(Law No: 5346, Issuance Date: 18.05.2005)13, which is 7.3 USDcent/kWh. This price can be
accepted as conservative, since it represents the minimum guaranteed price for electricity
originating from wind energy projects. The price in the free electricity trade market is generally
higher than that.
3) EUR/TRY Exchange Rate is calculated using the Turkish Central Bank data 18 . This can be
accepted as reliable and conservative since it assumes a period long enough (a five year period
of [2007-2011]) as the reference.
4) EUR/USD Exchange Cross Rate is calculated using the Turkish Central Bank data19. This can
also be accepted as reliable and conservative since it assumes a period long enough (a five year
period of [2007-2011]) as the reference.
5) The Average Expected Annual Electricity Generation Amount is calculated by multiplying the
project generation of the project activity indicated in the licence by the ratio found by dividing
the total firm generations of CDM-VER Wind Projects in Turkey by their total project
generations for 2011, receiving the data from 2012 Capacity Projection Report of TEIAS4. The
firm energy generation capacity values in this report are based on actual generations of the
power plants. By this way, the annual estimated firm energy generation capacity for the project is
found. This can also be assumed as reliable and conservative, since it uses the official value
from a government source, and takes all the wind farms similar to the project activity into
account for a one-year period, a duration that is generally accepted long enough (minimum) for
wind power feasibility studies.
6) To find the net amount of electricity generated by the project activity, the electricity drawn from
the grid by the project should also be taken into account and subtracted from the amount of
electricity fed into the grid. However, no reliable and official data could be found regarding the
energy drawn from the grid by power plants. Hence, this estimated amount of energy drawn
from the grid was simply ignored. This can also be assumed as acceptable since this drawn
energy is small enough to be included in the error range of estimated energy fed into the grid.
7) The Euribor values used in the calculation for loan repayment and interests in the investment
analysis were also received from a reliable source20, and calculated for the same 5-year reference
period ([2007-2011]), as in the other parameters.
8) The values for Service, Operation and Maintenance Costs were calculated taking the Aksu Wind
Power Project Service and Availability Agreement with Wind Turbine Provider.
9) The values for credit were taken from the Credit Loan Agreement made between the Creditor
Bank and the Project Proponent.
10) The project lifetime period was accepted as 20 years.
A summary of the benchmark analysis and the relevant parameters can be found in the following table:
18
http://evds.tcmb.gov.tr/cgi-bin/famecgi?cgi=$ozetweb&DIL=UK&ARAVERIGRUP=bie_dkdovizgn.db
http://evds.tcmb.gov.tr/cgi-bin/famecgi?cgi=$ozetweb&DIL=UK&ARAVERIGRUP=bie_dkdovizgn.db
20
http://www.euribor-ebf.eu/euribor-org/euribor-rates.html
19
UNFCCC/CCNUCC
Page 24
Table 11. Summary of Benchmark Analysis and Financial Data
Parameter
Unit
Value
Installed Capacity
MW
Expected Annual Firm
Energy Generation
MWh
Carbon Credit Unit Price
USD/tCO2-eq
8.00
Energy Unit Price
USDcent/kWh
7.30
Emission Factor
tCO2/MWh
0.611
Risk Free Rate (Rf)
%
13.50
Beta Coefficient (βi)
-
0.798
Market Risk Premium
(E(Rm) – Rf)
%
10.09
Benchmark Discount
Rate (Expected Returns
on Equity)
%
21.57
EUR/TRY Exchange Rate
-
2.0276
-
1.3916
EUR/USD Exchange
Cross Rate
Total Investment Cost
Total Operation and
Maintenance Costs
Equity / Total Investment
Cost Ratio
Debt / Total Investment
Cost Ratio
Project Lifetime
Equity IRR
72
194,003
EUR
79,882,500
EUR
29,083,252
Reference / Source / Justification
Project Activity Electricity Generation
Licence
Project Activity Electricity Generation
Licence, Firm/Project Generation Capacity
Data of CDM-VER Wind Projects from
2012 Capacity Projection Report of TEIAS
Ecosystem Marketplace State of the
Voluntary Carbon Markets 2012 Report
Law on Utilization of Renewable Energy
Resources for the Purpose of Generating
Electrical Energy (Law No: 5346, Issuance
Date: 18.05.2005)
Emission Factor Calculation, made
according to “Tool to calculate the emission
factor for an electricity system-Version
03.0.0”
EUROSTAT Data for Turkey for the 5-year
period of [2007-2011]
Istanbul Stock Exchange Data for the 5-year
period of [2007-2011]
Data for Turkey for the 5-year period of
[2007-2011] from Studies of Prof. Aswath
Damodaran.
Calculated using the relevant parameters
according to the Capital Asset Pricing Model
(CAPM).
Turkish Central Bank Data for the 5-year
period of [2007-2011]
Turkish Central Bank Data for the 5-year
period of [2007-2011]
Investment Analysis
Aksu Wind Power Project Service and
Availability Agreement with Wind Turbine
Provider
%
23 Investment Analysis
%
77 Investment Analysis
Years
%
20 Assumption
9.38 Investment Analysis Cash Flow
Comparison results of financial indicators can be summarized and depicted in the table below:
Table 12. Comparison results of financial indicators
Indicator
Value
Benchmark Discount Rate
21.57 %
UNFCCC/CCNUCC
Page 25
Equity IRR with Carbon Revenues
Equity IRR without Carbon Revenues
9.38 %
7.16 %
The results of the comparison show that without the extra income of carbon revenues, the Equity IRR of
the project activity is equal to 7.16 % and lower than the benchmark discount rate, which is 21.57 %.
This clearly indicates that the project activity cannot be considered as financially attractive.
With carbon revenues, Equity IRR value is 9.38 %, which is also lower than the benchmark discount rate
of 21.57 %. But carbon revenues give extra financial support to the project development and alleviate the
financial hardships. Taking the VER Carbon Revenues into account brings some extra co-benefits to the
project developer like fulfilling the Social Corporate Responsibility in an environment-friendly way,
helping promote the image of the project developer, and increasing the chance of getting future
incentives. Most importantly, additional financial income, extra detailed financial and environmental
feasibility and documentation studies, and extra care taken in by developing the project as a CDM-VER
Project greatly increases the probability of finding debt from a credit institution.
Sub-step 2d: Sensitivity analysis (only applicable to Options II and III)
A Sensitivity Analysis was made in order to show whether the conclusion regarding the
financial/economic attractiveness is robust to reasonable variations in the critical assumptions. For this
purpose, the sensitivity analysis is applied to following parameters:
1)
2)
3)
4)
Total Project Cost
Operational, Service and Maintenance Costs
Electrical Energy Generation
Electrical Energy Sales Price
The sensitivity analysis was applied to these parameters for two cases, one with carbon revenues, and
the other without carbon revenues; and for a range of ± 20 %, with increments of 5 %. The results are
summarized in the table below:
Table 13. Parameters and Variances Used in Sensitivity Analysis
Variable
Variance
Amount (EUR)
IRR (with VER
Revenues)
IRR (without
VER Revenues)
Total Project Cost
-20%
-15%
Total Amount
(EUR)
IRR (with VER
Revenues)
IRR (without
VER Revenues)
-5%
0%
5%
10%
15%
20%
61,882,737 65,750,408 69,618,079 73,485,750 77,353,421 81,221,092 85,088,763 88,956,434 92,824,105
16.78%
14.50%
12.56%
10.86%
9.38%
8.07%
6.86%
5.80%
4.91%
13.78%
11.76%
10.02%
8.50%
7.16%
5.98%
4.92%
4.02%
3.25%
10%
15%
20%
Variable
Variance
-10%
Operational, Service & Maintenance Costs
-20%
-15%
-10%
-5%
0%
5%
36,775,865 39,074,357 41,372,848 43,671,340 45,969,832 48,268,323 50,566,815 52,865,306 55,163,798
10.75%
10.41%
10.07%
9.73%
9.38%
9.04%
8.69%
8.34%
7.99%
8.55%
8.21%
7.86%
7.51%
7.16%
6.81%
6.46%
6.10%
5.74%
UNFCCC/CCNUCC
Page 26
Variable
Electrical Energy Generation
Variance
Amount (MWh)
IRR (with VER
Revenues)
IRR (without
VER Revenues)
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
155,202
164,902
174,602
184,302
194,003
203,703
213,403
223,103
232,803
2.26%
4.09%
5.85%
7.61%
9.38%
11.16%
12.97%
14.79%
16.65%
0.33%
2.13%
3.86%
5.52%
7.16%
8.82%
10.49%
12.17%
13.87%
Variable
Electrical Energy Sales Price
Variance
Amount
(EURcent/kWh)
IRR (with VER
Revenues)
IRR (without
VER Revenues)
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
4.20
4.46
4.72
4.98
5.25
5.51
5.77
6.03
6.30
2.72%
4.42%
6.07%
7.72%
9.38%
11.05%
12.74%
14.45%
16.18%
0.33%
2.13%
3.86%
5.52%
7.16%
8.82%
10.49%
12.17%
13.87%
The same results are also illustrated in the following figure:
Figure 3. Sensitivity Analysis Results
Sensitivity Analysis
Benchmark Rate
25%
Project Costs with
VER
20%
Project Costs
without VER
Operational Service
& Maintenance
Costs with VER
15%
IRR
(%)
Operational Service
& Maintenance
Costs without VER
10%
Electrical Energy
Generation with VER
Electrical Energy
Generation without
VER
5%
Electrical Energy
Sales Price with VER
0%
-20%
-15%
-10%
-5%
0%
Sensitivity (%)
5%
10%
15%
20%
Electrical Energy
Sales Price without
VER
The results found in the sensitivity analysis indicated that under all alternative scenarios for all the
parameters selected with different variances, the Equity IRR value could not reach the Benchmark
Discount Rate of 21.57 %.
UNFCCC/CCNUCC
Page 27
Hence, the sensitivity analysis showed that the conclusion regarding financial/economic attractiveness of
the project is robust to reasonable variations in the critical assumptions.
The details of investment analysis can be found in the separate spreadsheet file supplied as an annex to
this PDD.
Outcome of Step 2: The project activity is unlikely to be financially/economically attractive.
Step 3: Barrier analysis
This step is not applied.
Step 4: Common practice analysis
According to “Tool for the demonstration and assessment of additionality-Version 07.0.0” (Hereafter
referred to as “The Tool” in this section regarding the Common Practice Analysis) and “Guidelines on
common practice-Version 02.0”, (Hereafter referred to as “The Guidelines” in this section regarding the
Common Practice Analysis), the Common Practice Analysis procedure was applied for the project
activity.
The project activity is a wind farm realizing power generation based on renewable energy. Hence, it falls
under the category defined in the sub-clause (ii) in the “Measure” definition of the Tool (page 5) and
sub-clause (b) in the “Measure” definition of the Guidelines (page 1):
“Switch of technology with or without change of energy source including energy efficiency
improvement as well as use of renewable energies (example: energy efficiency improvements, power
generation based on renewable energy); “
As a result, sub-step 4a was applied.
Sub-step 4a: The proposed CDM project activity(ies) applies measure(s) that are listed in the
definitions section above
According the rules of the Guideline, the applicable geographical area is Turkey, and the output of the
project activity is electricity.
The stepwise approach for common practice described in the second section of the Guidelines was
applied.
For Step 1 of this stepwise approach, the calculation of the output range is done based on the installed
capacity of the project. Since the installed capacity of the project is 72 MW, the output range will be 72
+/- 50 % = [36 – 108] MW.
For Step2, firstly, identification of the similar projects was done according to the sub-paragraphs (a),
(b), (c), (d) and (f) of paragraph 6 of the stepwise approach, as described on page 2 - 3 of the
Guidelines. The result of this first phase is operational wind farms in Turkey at the date when the project
activity is first commissioned. The below table shows these power plants:
UNFCCC/CCNUCC
Page 28
Table 14. Operational Wind Power Plants in Turkey as at the Date of Commissioning of the Project
Wind Projects in Turkey (As at the Commissioning of the Project)
Legal
Status
Power Plant Name
Installed
Location
Capacity
(Province)
MW
1
2
3
4
5
6
7
BOT
ARES (ALAÇATI)
BOT
BORES (BOZCAADA)
AP
SUNJÜT
1.2 Istanbul
IPP
ALİZE ENERJİ (DELTA PLASTİK)
1.5 Izmir
IPP
ERTÜRK ELEKT. (TEPE)
IPP
ALİZE ENERJİ (ÇAMSEKİ)
20.8 Canakkale
IPP
8
IPP
9
IPP
ALİZE ENERJİ (KELTEPE)
ALİZE ENERJİ (SARIKAYA
ŞARKÖY)
AK ENERJİ AYYILDIZ
(BANDIRMA)
IPP
1
0
1
1
1
2
1
3
1
4
1
5
1
6
1
7
1
8
1
9
2
0
2
1
2
2
2
3
2
4
2
5
2
6
Commissioning
Date
VER
Standard
VER Standard
Code /
Number /
Project ID
7.2 Izmir
10.2 Canakkale
0.9 Istanbul
2005-04-22
20.7 Balikesir
2006-12-22
2009-06-24 GS
2010-04-28 GS
GS399
GS437
28.8 Tekirdag
2009-10-19 GS
GS577
15.0 Balikesir
2009-07-23 GS
GS634
AKDENİZ ELEK. MERSİN RES
33.0 Mersin
2010-03-19 GS
GS753
IPP
AKRES (AKHİSAR RÜZGAR)
43.8 Manisa
2011-09-23 GS
GS955
IPP
ANEMON ENERJİ (İNTEPE)
30.4 Canakkale
2007-11-22 GS
GS347
IPP
ASMAKİNSAN (BANDIRMA-3 RES)
24.0 Balikesir
2010-03-26 GS
GS683
IPP
AYEN ENERJİ (AKBÜK)
31.5 Aydin
2009-04-03 GS
GS436
IPP
AYVACIK (AYRES)
2011-10-23 GS
GS956
IPP
BAKRAS ELEK.ŞENBÜK RES
15.0 Hatay
2010-04-22 GS
GS733
IPP
BARES (BANDIRMA)
30.0 Balikesir
2011-08-11
IPP
BELEN HATAY
36.0 Hatay
2010-09-02 GS
GS390
IPP
BERGAMA RES (ALİAĞA RES)
90.0 Izmir
2010-06-16 GS
GS735
IPP
BORASKO BANDIRMA
60.0 Balikesir
2010-06-30 GS
GS744
IPP
BOREAS EN.(ENEZ RES)
15.0 Edirne
2010-04-09 GS
GS702
IPP
ÇANAKKALE RES (ENERJİ-SA)
29.9 Canakkale
2011-05-06 GS
GS906
IPP
ÇATALTEPE (ALİZE EN.)
16.0 Balikesir
2011-04-19 GS
GS574
IPP
DOĞAL ENERJİ (BURGAZ)
14.9 Canakkale
2008-05-08 GS
GS439
IPP
DENİZLİ ELEKT. (KarakurtAkhisar)
10.8 Manisa
2007-05-28
IPP
MARE MANASTIR
39.2 Izmir
2007-04-13 GS
5.0 Canakkale
GS,
VER+
VCS,
VER+
GS1072,
52-1
66
GS368
UNFCCC/CCNUCC
2
7
2
8
2
9
3
0
3
1
3
2
3
3
3
4
3
5
3
6
3
7
3
8
3
9
4
0
4
1
4
2
4
3
4
4
4
5
4
6
4
7
4
8
4
9
5
0
5
1
Page 29
IPP
MAZI 3
30.0 Izmir
2010-06-18 GS
GS388
IPP
KİLLİK RES (PEM EN.)
40.0 Tokat
2011-12-17 GS
GS947
IPP
KORES KOCADAĞ
15.0 Izmir
2009-12-23 GS
GS601
IPP
KUYUCAK (ALİZE ENER.)
25.6 Manisa
2010-12-09 GS
GS576
IPP
ROTOR (OSMANİYE RESGÖKÇEDAĞ RES)
135.0 Osmaniye
2010-10-15 GS
GS474
IPP
BAKİ ELEKTRİK ŞAMLI RÜZGAR
114.0 Balikesir
2011-11-13 GS
GS351
IPP
DATÇA RES
29.6 Mugla
2009-12-24 GS
GS438
IPP
ERTÜRK ELEKT. (ÇATALCA)
60.0 Istanbul
2008-12-27 GS
GS367
IPP
İNNORES ELEK. YUNTDAĞ
52.5 Izmir
2011-09-27 GS
GS352
IPP
LODOS RES
(TAŞOLUK)KEMERBURGAZ
24.0 Istanbul
2008-08-20 GS
GS503
IPP
SARES (GARET ENER.)
22.5 Canakkale
2011-03-10 GS
GS963
IPP
SAYALAR RÜZGAR (DOĞAL
ENERJİ)
34.2 Manisa
2009-09-06 GS
GS369
IPP
SEBENOBA (DENİZ
ELEK.)SAMANDAĞ
30.0 Hatay
2010-03-12
IPP
SEYİTALİ RES (DORUK EN.)
30.0 Izmir
2011-07-22 GS
GS578
IPP
SOMA RES
116.1 Manisa
2011-12-09 GS
GS398
IPP
SOMA RES (BİLGİN ELEK.)
90.0 Manisa
2010-11-11 GS
GS655
IPP
SUSURLUK (ALANTEK EN.)
45.0 Balikesir
2011-05-20 GS
GS854
IPP
ŞAH RES (GALATA WIND)
93.0 Balikesir
2011-07-29 GS
GS905
IPP
TURGUTTEPE RES (SABAŞ
ELEK.)
24.0 Aydin
2011-03-04 GS
GS610
IPP
ÜTOPYA ELEKTRİK
30.0 Izmir
2010-09-03 GS
GS672
IPP
ZİYARET RES
57.5 Hatay
2011-11-24 GS
GS617
IPP
SÖKE-ÇATALBÜK RES
30.0 Aydin
2012-01-08 GS
GS653
VCS,
VER+
553
IPP
BOZYAKA RES
12.0 Izmir
2012-03-12 GS
Markit GS
Registry ID:
103000000
001624
IPP
METRİSTEPE RES
27.5 Bilecik
2012-03-12 GS
GS1067
IPP
KAYADÜZÜ RES
2012-03-16 GS
GS950
7.5 Amasya
Abbreviations: BOT: Build-Operate-Transfer, AP: Autoproducer, IPP: Independent Power
Producer, VER: Verified Emission Reduction, GS: Gold Standard, VCS: Verified Carbon Standard
UNFCCC/CCNUCC
Page 30
47 wind farms were operational at the end of 201121. Four more wind farms had become operational in
2012 when the project activity was commissioned 22. As can be seen from the table, most of the wind
farms (46 of 51) have been developed as CDM project activities. Only 5 wind farms are non-CDM
projects. The reasons for their being non-CDM wind power projects is due to their legal status (BOT or
Autoproducer), their early commissioning before the applicability of VER scheme or their small installed
capacity size.
If we apply the output range criterion for the identification of similar projects, as indicated in subparagraph (e) of paragraph 6 of the stepwise approach, all these 5 non-CDM projects will be eliminated,
along with some of the CDM projects.
If we further proceed with Steps (3), (4) and (5) of the same stepwise approach, as explained in the
paragraphs, (7), (8) and (9) of the stepwise approach of the Guideline, we will see that no projects can
be identified as similar to the project. Hence Nall = 0, Ndiff = 0, and the formula F = 1- Ndiff /Nall becomes
not applicable. Also, as per the paragraph (10), F is indefinite and Nall - Ndiff = 0 is less than 3. So, the
proposed project activity is not a “common practice”.
Hence, no similar projects could be found according to the Common Practice Analysis made according
to the Tool and the Guidelines, the project activity is not common practice.
Outcome of Step 4: The outcome of Step 4 is that the proposed project activity is not regarded as
“common practice”, hence, the proposed project activity is additional.
B.6. Emission reductions
B.6.1. Explanation of methodological choices
To establish the baseline scenario for the project, and to calculate the baseline emissions, project
emissions, leakage and emission reductions, the latest version of the official methodology, “ACM0002:
Consolidated baseline methodology for grid-connected electricity generation from renewable sources --Version 13.0.0” (Hereafter referred to as “The Methodology” in this section regarding the Emission
reductions) and the latest version of the official tool “Tool to calculate the emission factor for an
electricity system – Version 03.0.0” (Hereafter referred to as “The Tool” in this section regarding the
Emission reductions) were used.
The applicability of “ACM0002: Consolidated baseline methodology for grid-connected electricity
generation from renewable sources --- Version 13.0.0” (The Methodology) is justified according to the
explanation given under the heading of “Applicability” on pages 2 and 3 of the Methodology, as follows:
“Applicability
This methodology is applicable to grid-connected renewable power generation project activities that:
(a) install a new power plant at a site where no renewable power plant was operated prior to the
21
Turkish Electrical Energy 10-Year Generation Capacity Projection Report (2012-2021), Annex-1: Current System (As at the
end of 2011) pp 109 - 123. (http://www.teias.gov.tr/KapasiteProjeksiyonuARALIK2012.pdf)
22
http://www.enerji.gov.tr/yayinlar_raporlar/2012_Yili_Enerji_Yatirimlari.xls
UNFCCC/CCNUCC
Page 31
implementation of the project activity (greenfield plant); (b) involve a capacity addition; (c) involve a
retrofit of (an) existing plant(s); or (d) involve a replacement of (an) existing plant(s).
The methodology is applicable under the following conditions:

The project activity is the installation, capacity addition, retrofit or replacement of a power
plant/unit of one of the following types: hydro power plant/unit (either with a run-of-river
reservoir or an accumulation reservoir), wind power plant/unit, geothermal power plant/unit,
solar power plant/unit, wave power plant/unit or tidal power plant/unit;”
Since the project is wind power greenfield plant, the Methodology is applicable.
Baseline Scenario is also identified according to the rules under the heading of “Baseline Methodology
Procedure” on page 4 of the Methodology:
“Identification of the baseline scenario
If the project activity is the installation of a new grid-connected renewable power plant/unit, the baseline
scenario is the following:

Electricity delivered to the grid by the project activity would have otherwise been generated by
the operation of grid-connected power plants and by the addition of new generation sources, as
reflected in the combined margin (CM) calculations described in the “Tool to calculate the
emission factor for an electricity system.”
Since the project activity is a wind power plant, project emissions are accepted as zero, PEy = 0. The
project activity involves no emissions, except from a diesel generator used for emergency backup
purposes. The possible emissions from the use of fossil fuels for the back up or emergency purposes by
the operation of this diesel generator are neglected according to the methodology.
Leakage emissions are also neglected as per the Methodology.
Baseline emissions are considered according to the following explanations and formulas included in the
Methodology:
“Baseline emissions
Baseline emissions include only CO2 emissions from electricity generation in fossil fuel fired power
plants that are displaced due to the project activity. The methodology assumes that all project electricity
generation above baseline levels would have been generated by existing grid-connected power plants
and the addition of new grid-connected power plants. The baseline emissions are to be calculated as
follows:
BE y  EGPJ , y * EFgrid,CM , y
(1)
Where:
BE y
=
Baseline emissions in year y (tCO2/yr)
EGPJ , y
=
EFgrid ,CM , y
=
Quantity of net electricity generation that is produced and fed into the grid as a result
of the implementation of the CDM project activity in year y (MWh/yr)
Combined margin CO2 emission factor for grid connected power generation in year y
calculated using the latest version of the “Tool to calculate the emission factor for an
electricity system” (tCO2/MWh)
Calculation of EGPJ,y
UNFCCC/CCNUCC
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The calculation of EGPJ,y is different for: (a) greenfield plants, (b) retrofits and replacements; and
(c) capacity additions. These cases are described next.
(a) Greenfield renewable energy power plants
If the project activity is the installation of a new grid-connected renewable power plant/unit at a site
where no renewable power plant was operated prior to the implementation of the project activity, then:
EG PJ,y  EG facility, y
(2)”
Emission reduction calculations are similarly based on the relevant section of the Methodology:
“Emission reductions
Emission reductions are calculated as follows:
ERy  BE y  PE y
(3)
Where:
ERy
=
Emission reductions in year y (tCO2e/yr)
BE y
=
PE y
=
Project emissions in year y (tCO2e/yr)
Estimation of emissions reductions prior to validation
Project participants should prepare as part of the CDM-PDD an estimate of likely emission reductions
for the proposed crediting period. This estimate should, in principle, employ the same methodology as
selected above. Where the grid emission factor (EFCM,grid,y) is determined ex post during monitoring,
project participants may use models or other tools to estimate the emission reductions prior to
validation.”
Since PEy = 0, ERy = BEy. So, in order to calculate the emission reductions for the project, it will suffice
to calculate the baseline emissions. Calculation of the baseline emissions was done according to the Tool
as indicated in the Methodology.
Six-steps in the stepwise baseline methodology procedure in the Tool were followed to calculate the
baseline emissions:
“Baseline methodology procedure
13. Project participants shall apply the following six steps:
(a) STEP 1: identify the relevant electricity systems;
(b) STEP 2: choose whether to include off-grid power plants in the project electricity system (optional);
(c) STEP 3: select a method to determine the operating margin (OM);
(d) STEP 4: calculate the operating margin emission factor according to the selected method;
(e) STEP 5: calculate the build margin (BM) emission factor;
UNFCCC/CCNUCC
Page 33
(f) STEP 6: calculate the combined margin (CM) emission factor.”
Step 1: Identify the relevant electricity systems
In the Tool, on page 5 - 6, the project electricity system is defined as:
“A grid/project electricity system - is defined by the spatial extent of the power plants that are physically
connected through transmission and distribution lines to the project activity (e.g. the renewable power
plant location or the consumers where electricity is being saved) and that can be dispatched without
significant transmission constraints;”
Also, on page 6 of the Tool, connected electricity system is defined as:
“Connected electricity system - is an electricity system that is connected by transmission lines to the
project electricity system. Power plants within the connected electricity system can be dispatched without
significant transmission constraints but transmission to the project electricity system has significant
transmission constraint, and/or the transmission capacity of the transmission line(s) that is connecting
electricity systems is less than 10 per cent of the installed capacity either of the project electricity system
or of the connected electricity system, whichever is smaller;”
The project activity is connected to the national grid of Turkey. There is no DNA in Turkey which has
published a delinaeation of the project electricity system and the connected electricity systems. Since
such information is not available, the criteria for the transmission constraints suggested on page 7 of the
Tool were used to clarify the definitions of the project electricity system and the connected electricity
systems. There are no available spot electricity markets in Turkey at the time of writing of this report.
Also, there are no official data on availability or operational time of transmission lines in Turkey. Hence,
these two criteria are not applicable.
There are interconnections between Turkey and all its neighbouring countries. However, these lines are
in limited capacity and have significant transmission constraints as compared to national transmission
lines in Turkey.23,24 In addition, international electricity trade through these transboundary transmission
lines has legal restrictions and is subject to permission of EMRA (Republic of Turkey Energy Market
Regulatory Authority).25,26,27
The Turkish National Grid is operated by the responsible authority of TEIAS (Turkish Electricity
Transmission Corporation). All the power plants in this system can be dispatched without significant
transmission constraints. There are no layered dispatch systems (e.g. provincial/regional/national) within
this national system.28,29,30 So, there are no independent separate grids in the national grid.
In the light of above information and the paragraphs (17) and (18) on the page 7 of the Tool, the project
electricity system is defined as Turkish National Grid, and the connected electricity systems are defined
23
http://www.teias.gov.tr/Dosyalar/NetTransferKapasiteleri.doc
http://212.175.131.171/makaleler/ENTSOE%20Bağlantısı%20ICCI%20v3.pdf
25
http://www.epdk.gov.tr/documents/elektrik/mevzuat/yonetmelik/elektrik/ithalat_ihracat/Elk_Ynt_ithalat_ihracat_SonHali.doc
26
http://www.epdk.gov.tr/documents/elektrik/mevzuat/yonetmelik/elektrik/ithalat_ihracat/iliskili_mevzuat/KapasiteTahsisiEsaslar.doc
27
http://www.epdk.gov.tr/index.php/elektrik-piyasasi/lisans?id=818
28
http://www.teias.gov.tr/Hakkimizda.aspx
29
http://212.175.131.171/Faaliyet2011/ING_Teias.pdf
30
http://geni.org/globalenergy/library/national_energy_grid/turkey/
24
UNFCCC/CCNUCC
Page 34
as the neighbouring countries of Turkey, all of which are connected to Turkish national grid by
transboundary transmission lines.
As per the paragraphs (19), (20), (21), (22) and (23) on page 8 of the Tool, electricity imports and
exports and their usage in the emission calculations are defined. For the purpose of determining the
operating margin emission factor, the CO 2 emission factor for net electricity imports from the connected
electricity systems is accepted as 0 t CO2/MWh according to paragraph (21), sub-paragraph (a) of the
Tool, and the electricity exports are not subtracted from electricity generation data used for calculating
and monitoring the electricity emission factors according to paragraph (23) of the Tool.
Step 2: Choose whether to include off-grid power plants in the project electricity system
(optional)
The Tool suggests two options between which the project participants may choose to calculate the
operating margin and build margin emission factor:
Option I
: Only grid power plants are included in the calculation.
Option II
: Both grid power plants and off-grid power plants are included in the calculation.
The rationale behind Option II is explained in the Tool as “Option II provides the option to include offgrid power generation in the grid emission factor. Option II aims to reflect that in some countries offgrid power generation is significant and can partially be displaced by CDM project activities, that is if
off-grid power plants are operated due to an unreliable and unstable electricity grid.”
This is not the case for the National Grid of Turkey, the selected project system. The contribution of the
off-grid power plants to Turkish grid is negligible and no official or reliable data regarding the off-grid
power plants in Turkey could be found. So, Option II is not appropriate.
Hence, Option I is selected and only grid power plants are included in the calculation of the operating
margin and build margin emission factors.
Step 3: Select a method to determine the operating margin (OM)
The Tool gives four following method options for the calculation of the operating margin emission
factor (EFgrid,OM,y):
(a) Simple OM, or
(b) Simple adjusted OM, or
(c) Dispatch data analysis OM, or
(d) Average OM
Since power plant specific data for generation, emission or emission factor are not available, “Simple
adjusted OM” and “Dispatch data analysis OM” methods are not applicable. This also renders Option A
of “Simple OM” method not applicable. The remaining two methods are Option B of “Simple OM” and
“Average OM” methods. To decide between these two alternative methods, we have to take the situation
of low-cost/must-run power plants into account. Following table summarizes the generation amounts
and percentage of low-cost/must-run power plants for the five most recent years available at the time of
writing of this report, that is, the period of [2007 – 2011].
Table 15. The Contribution of Low-Cost/Must-Run Power Plants to the Gross Generation of Turkey for
the 5-year period of [2007 – 2011]
UNFCCC/CCNUCC
Page 35
Gross Generations and Percentages by Fuel Types and Primary Energy Resources of Low-Cost/Must-Run Power Units in Turkey
(Unit: GWh)
Years
Primary Energy Resource or Fuel Type
5-Year
Total
5-Year
Percentage
2007
2008
2009
2010
2011
Hard Coal + Imported Coal + Asphaltite
15,136.2
15,857.5
16,595.6
19,104.3
27,347.5
94,041.1
9.17%
Lignite
38,294.7
41,858.1
39,089.5
35,942.1
38,870.4
194,054.8
18.92%
Total Coal
53,430.9
57,715.6
55,685.1
55,046.4
66,217.9
288,095.8
28.10%
6,469.6
7,208.6
4,439.8
2,143.8
900.5
21,162.3
2.06%
13.3
266.3
345.8
4.3
3.1
632.8
0.06%
0.0
0.0
0.4
0.0
0.0
0.4
0.00%
43.9
43.6
17.6
31.9
0.0
137.0
0.01%
6,526.8
7,518.5
4,803.5
2,180.0
903.6
21,932.4
2.14%
95,024.8
98,685.3
96,094.7
98,143.7
104,047.
6
491,996.1
47.98%
213.7
219.9
340.1
457.5
469.2
1,700.5
0.17%
Thermal
155,196.
2
164,139.
3
156,923.
4
155,827.
6
171,638.
3
803,724.8
78.38%
Hydro + Geothermal + Wind Total
36,361.9
34,278.7
37,889.5
55,380.1
57,756.8
221,667.0
21.62%
Hydro
35,850.8
33,269.8
35,958.4
51,795.5
52,338.6
209,213.1
20.40%
511.1
1,008.9
1,931.1
3,584.6
5,418.2
12,453.9
1.21%
General Total (Gross)
191,558.
1
198,418.
0
194,812.
9
211,207.
7
229,395.
1
1,025,391.
8
100.00%
Gross - Low-Cost/Must-Run
36,361.9
34,278.7
37,889.5
55,380.1
57,756.8
221,667.0
21.62%
Gross Excluding Low-Cost/Must-Run (Thermal)
155,196.
2
164,139.
3
156,923.
4
155,827.
6
171,638.
3
803,724.8
78.38%
Fuel-Oil
Diesel Oil
LPG
Naphtha
Total Oil (Liquid Total)
Natural Gas
Geothermal + Wind
The selection of the low-cost/must run power plants was done according to the definition on page 6 of
the Tool:
“Low-cost/must-run resources - are defined as power plants with low marginal generation costs or
dispatched independently of the daily or seasonal load of the grid. They include hydro, geothermal,
wind, low-cost biomass, nuclear and solar generation. If a fossil fuel plant is dispatched independently
of the daily or seasonal load of the grid and if this can be demonstrated based on the publicly available
data, it should be considered as a low-cost/must-run;”
Hence, the selection in the table which assumes the total of hydro, geothermal and wind as the lowcost/must-run resources is justified. Since there are no nuclear power plants and also no grid-connected
solar power plants in Turkey at the time of writing of this report, these resource types are automatically
excluded.
As can be seen from the table, low-cost/must-run resources constitute less than 50 per cent of total grid
generation (excluding electricity generated by off-grid power plants) in average of the five most recent
years [2007 – 2011], which is in line with the relevant rule, paragraph 34 on page 9 – 10 of the Tool:
UNFCCC/CCNUCC
Page 36
“The simple OM method (Option a) can only be used if low-cost/must-run resources constitute less than
50 per cent of total grid generation (excluding electricity generated by off-grid power plants) in: 1)
average of the five most recent years, or 2) based on long-term averages for hydroelectricity
production.”
The rules for the usability of Simple OM method Option, which was stated in paragraph 42, on page 11
of the Tool, as below, are also met:
“42. Option B can only be used if:
(a) The necessary data for Option A is not available; and
(b) Only nuclear and renewable power generation are considered as low-cost/must-run power sources
and the quantity of electricity supplied to the grid by these sources is known; and
(c) Off-grid power plants are not included in the calculation (i.e. if Option I has been chosen in Step 2).”
As a result, Option B of Simple OM method was selected as the method to determine the operating
margin.
Ex ante option was preferred to calculate the emissions factor, and the reference period was selected as
the three-year period of [2009 – 2011], as per the requirements stated in paragraph 36, sub-paragraph (a)
on page 10 of the Tool:
“36. For the simple OM, the simple adjusted OM and the average OM, the emissions factor can be
calculated using either of the two following data vintages:
(a) Ex ante option: if the ex ante option is chosen, the emission factor is determined once at the
validation stage, thus no monitoring and recalculation of the emissions factor during the crediting period
is required. For grid power plants, use a 3-year generation-weighted average, based on the most recent
data available at the time of submission of the CDM-PDD to the DOE for validation. For off-grid power
plants, use a single calendar year within the five most recent calendar years prior to the time of
submission of the CDM-PDD for validation;”
Step 4: Calculate the operating margin emission factor according to the selected method
Operating Margin Emission Factor was calculated using the formulation and procedure described in the
paragraphs (49) and (50) in sub-section 6.4.1.2., on pages 14 – 15 of the Tool:
“6.4.1.2. Option B: Calculation based on total fuel consumption and electricity
generation of the system
49.
Under this option, the simple OM emission factor is calculated based on the net electricity
supplied to the grid by all power plants serving the system, not including low-cost/must-run
power plants/units, and based on the fuel type(s) and total fuel consumption of the project
electricity system, as follows:
EFgrid,OMsimple, y 
 FC
i
i, y
 NCVi , y  EFCO2 ,i , y
EG y
Equation (7)
UNFCCC/CCNUCC
Page 37
Where:
EFgrid,OMsimple,
y
FCi,y
NCVi,y
EFCO2,i,y
EGy
i
y
50.
= Simple operating margin CO2 emission factor in year y
(t CO2/MWh)
= Amount of fuel type i consumed in the project electricity system in
year y (mass or volume unit)
= Net calorific value (energy content) of fuel type i in year y (GJ/mass or volume
unit)
= CO2 emission factor of fuel type i in year y (t CO2/GJ)
= 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)
= All fuel types combusted in power sources in the project electricity system in year y
= The relevant year as per the data vintage chosen in Step 3
For this approach (simple OM) to calculate the operating margin, the subscript m refers to the
power plants/units delivering electricity to the grid, not including low-cost/must-run power
plants/units, and including electricity imports5 to the grid. Electricity imports should be treated as
one power plant m.”
Fossil fuel types and their amounts were taken from the official data of Electricity Generation &
Transmission Statistics of Turkey, published by TEIAS (Turkish Electricity Transmission Company, the
state authority responsible for the national transmission system of Turkey), as indicated in the table
below1:
Table 16. Fuel Consumption in Electricity Generation in Turkey for the 3-year period of [2009 – 2011]
Fuel Consumption in Electricity
Generation Excluding LowCost/Must-Run (Unit: Ton (solid
and liquid) /103 m3 (gas))
Years
2007
2008
2009
2010
2011
Hard Coal+Imported
6,029,143.0
6,270,008.0
6,621,177.0
7,419,703.0 10,574,434.0
Coal+Asphaltite
Lignite
61,223,821.0 66,374,120.0 63,620,518.0 56,689,392.0 61,507,310.0
Fuel Oil
2,250,686.0
2,173,371.0
1,594,321.0
891,782.0
531,608.0
Diesel oil
50,233.0
131,206.0
180,857.0
20,354.0
15,047.0
LPG
0.0
0.0
111.0
0.0
0.0
Naphtha
11,441.0
10,606.0
8,077.0
13,140.0
0.0
Natural Gas
20,457,793.0 21,607,635.0 20,978,040.0 21,783,414.0 22,804,587.0
Renewables and Wastes*
* Since heating values and fuel amounts of renewable and waste materials are not included in
TEIAS Statistics, these are also ignored here.
To calculate the Net Calorific Values, data on heating values of fuels consumed in thermal power plants
in Turkey by the electric utilities31 along with the fuel amounts mentioned above were used.
31
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2011/yakıt46-49/49.xls
UNFCCC/CCNUCC
Page 38
Table 17. Heating Values of Fuels Consumed in Thermal Power Plants in Turkey by the Electric Utilities
[2006 – 2011]
Years
Heating Values of Fuels Consumed
in Thermal Power Plants (Unit: Tcal)
2007
2008
2009
2010
2011
Hard Coal+Imported Coal+Asphaltite
32,115.0
33,310.0
35,129.8
39,546.5
57,567.3
Lignite
100,320.0 108,227.0
97,651.6
96,551.0 107,209.5
Fuel Oil
21,434.0
20,607.0
15,159.9
8,569.1
5,279.9
Diesel oil
517.0
1,328.0
1,830.2
209.5
155.1
LPG
0.0
0.0
1.2
0.0
0.0
Naphtha
118.0
113.0
84.2
105.1
0.0
Natural Gas
179,634.0 189,057.0 186,265.8 194,487.3 202,064.1
Turkey's Thermal Total
334,138.0 352,642.0 336,122.7 339,468.5 372,275.9
* Since heating values and fuel amounts of renewable and waste materials are not
included in TEIAS Statistics, these are also ignored here.
Since there are no plant-specific or fuel-type specific emission factor data officially available in Turkey,
we have to use the emission factors published by IPCC.32 The related emission factors are indicated in
the following table:
Table 18. IPCC Default Emission Factor Values by Different Fuel Types
Table 1.4
Default CO2 Emission
Factors for Combustion
Fuel Type
Effective CO2 Emission Factor
(kg/TJ)
Default
Lower
Upper
Anthracite
98,300
94,600
101,000
Coking Coal
94,600
87,300
101,000
Other Bituminous Coal
94,600
89,500
99,700
Sub-Bituminous Coal
96,100
92,800
100,000
Lignite
101,000
90,900
115,000
Fuel Oil
77,400
75,500
78,800
Diesel Oil
74,100
72,600
74,800
LPG
63,100
61,600
65,600
Naphtha
73,300
69,300
76,300
Natural Gas
56,100
54,300
58,300
For the sake of conservativeness, the lower limits of the 95 percent confidence intervals were used in the
calculation of Operating Margin Emission Factor.
Since the emission factors of IPCC are based on mass-units, and the fuel consumption amounts for
natural gas is given in volume units in TEIAS statistics, we should convert the amount of natural gas
from volume units to mass units. For this purpose, the density of natural gas must be specified. Natural
32
http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_1_Ch1_Introduction.pdf
UNFCCC/CCNUCC
Page 39
Gas Density of Turkey for Electricity Generation was calculated using the data for Turkey in
International Energy Agency’s (IEA) Natural Gas Information (2010 Edition)33, IEA Key World Energy
Statistics 201134, and IEA Energy Statistics Manual35.
Turkey’s main natural gas supplier is Russian Federation, along with its neighbouring countries 36. This
fact is also confirmed by IEA Natural Gas Information 33 by comparing average gross calorific value of
natural gas of Turkey for consumption and that of Russian Federation for production. So, natural gas
produced and exported by Russian Federation and imported and consumed by Turkey was accepted as
the representative of natural gas used as fuel in electricity generation in Turkish National Grid.
To calculate the density of natural gas, the following table33 was used:
Table 19. Conversion Factors from Mass or Volume to Heat (Gross Calorific Value) for Natural Gas
Supplied by Russian Federation
GAS
Russia
To:
From:
cm*
MJ
Btu
multiply by:
38.23
Kg
55.25
* Standard Cubic Meters
36,235
52,363
This gives us a natural gas density of 0.692 kg/m3, which we used to calculate the mass of natural gas
used as fuel in power plants in Turkey for electricity generation.
As a result, the Fuel Consumption in Electricity Generation in Turkey can be shown again with all the
amounts in mass units as in the following table:
Table 20. Fuel Consumption in Electricity Generation in Turkey for the 3-year period of [2009 – 2011]
(in mass units)
Generation Excluding LowCost/Must-Run (Unit: Ton)
Hard Coal+Imported
Coal+Asphaltite
Lignite
Fuel Oil
Diesel oil
LPG
Naphtha
33
Years
2007
2008
2009
2010
2011
6,029,143.0
6,270,008.0
6,621,177.0
7,419,703.0
10,574,434.0
61,223,821.0
2,250,686.0
50,233.0
0.0
11,441.0
66,374,120.0
2,173,371.0
131,206.0
0.0
10,606.0
63,620,518.0
1,594,321.0
180,857.0
111.0
8,077.0
56,689,392.0
891,782.0
20,354.0
0.0
13,140.0
61,507,310.0
531,608.0
15,047.0
0.0
0.0
IEA Statistics, Natural Gas Information 2010, International Energy Agency - Introductory Information, Section 7, Abbreviations
and conversion factors, pp. xxvii - xxx.
34
http://www.iea.org/publications/freepublications/publication/key_world_energy_stats-1.pdf, Conversion Factors, pp. 58 – 60.
35
http://www.iea.org/publications/freepublications/publication/statistics_manual.pdf, Annex 3 Units and Conversion Equivalents –
Natural Gas – pp. 182 – 183.
36
BOTAS (Petroleum Pipeline Corporation) Natural Gas Purchase Agreements Information (http://www.botas.gov.tr/)
UNFCCC/CCNUCC
Page 40
Natural Gas
14,155,681.9 14,951,310.2 14,515,664.6 15,072,939.7 15,779,535.9
83,721,005.9 89,910,621.2 86,540,725.6 80,107,310.7 88,407,934.9
* Since heating values and fuel amounts of renewable and waste materials are not included in
TEIAS Statistics, these are also ignored here.
Net Calorific Values can be calculated using the heating values and the fuel amounts:
Table 21. Net Calorific Values calculated for fuel types in Electricity Generation in Turkey for the 3-year
period of [2009 – 2011]
Net Calorific Values of Fuels
Consumed in Thermal Power
Plants (Unit: TJ/Gg)
Hard Coal+Imported
Coal+Asphaltite
Lignite
Years
2007
2008
2009
2010
2011
22.3
22.2
22.2
22.3
22.8
6.9
6.8
6.4
7.1
7.3
Fuel Oil
39.9
39.7
39.8
40.2
41.6
Diesel oil
43.1
42.4
42.4
43.1
43.2
0.0
0.0
46.5
0.0
0.0
Naphtha
43.2
44.6
43.6
33.5
0.0
Natural Gas
53.1
52.9
53.7
54.0
53.6
0.0
0.0
LPG
0.0
0.0
0.0
* Assumed as zero due to unavailability of data and conservativeness
It is not very clear whether the heating values given in TEIAS statisitics31 are lower heating values (Net
Calorific Values = NCV) or higher heating values (Gross Calorific Values = GCV). However, some other
sources of state, academic and NGO (chamber of engineers) origin confirm that these are lower heating
values (net calorific values) by giving values in the same range as the calculated NCV values37,38,39,40,41,42.
Moreover, these data is compliant with the value given in National Inventory Reports and Common
Report Formats of Turkey submitted to UNFCCC, in which it was also stated that the heating values
given are NCV values43,44. As a result, these values are assumed to be the net calorific values of thermal
power plants in Turkey for the relevant period.
Turkey’s Net Electricity Generation by primary energy resources was not given in the TEIAS Turkish
Electricity Generation – Transmission Statistics 45 . Instead, Gross Electricity Generation by primary
37
http://enver.eie.gov.tr/DocObjects/Download/60094/TepHesap.xls
http://www.hkad.org/makaleler/cilt1/sayi1/HKAD-12-004.pdf
39
http://www.enerji.gov.tr/yayinlar_raporlar/Sektor_Raporu_TKI_2011.pdf
40
http://www.mmo.org.tr/resimler/dosya_ekler/a9393ba5ea45a12_ek.pdf
41
http://www.mmo.org.tr/resimler/dosya_ekler/b4d09fdaf9131ab_ek.pdf?dergi=1148
42
http://tez.sdu.edu.tr/Tezler/TF00997.pdf
43
http://unfccc.int/files/national_reports/annex_i_ghg_inventories/national_inventories_submissions/application/zip/tur-2013-nir15apr.zip
44
http://unfccc.int/files/national_reports/annex_i_ghg_inventories/national_inventories_submissions/application/zip/tur-2013-crf12apr.zip
45
http://www.teias.gov.tr/istatistikler.aspx, http://www.teias.gov.tr/Eng/StatisticalReports.aspx
38
UNFCCC/CCNUCC
Page 41
energy resources46, net generation amount and percentages for the whole national grid regardless of the
primary energy resources are available47. As a result, it becomes necessary to calculate the net generation
by primary energy resources by using these two data sets available.
For this purpose, the net/gross electricity generation ratio was assumed to be the same for all primary
energy resources. According to some studies made on this subject, the net/gross electricity generation
ratio of renewable energy power plants is slightly higher than that of thermal power plants 48,49. Since the
gross generation percentage of renewable energy power plants is lower than the percentage of thermal
power plants, using the same average net/gross electricity generation ratio for all power plants would
result in a slightly lower share for renewable energy power plants in the total net electricity generation
than it would be if we used the actual net/gross electricity generation ratios. Likewise, the net generation
share of thermal power plants will be slightly higher than that it would normally be. This would cause a
slightly higher operational margin emission factor value for the whole system, if we used all the power
plants including renewable ones, in the emission factor calculation. This would still be acceptable since
the difference between net/gross electricity generation ratio of renewable and non-renewable power
plants is very low (about 1 – 2 %), and could be assumed in the allowed error range.
However, by choosing Option B of Simple OM method for operating margin emission factor calculation,
we excluded all the low-cost/must-run power plants, that is, renewable ones. So, the impact of net/gross
electricity generation ratio for renewable power plants is automatically eliminated. Since the
corresponding ratio for different thermal plants is almost the same, using the same average net/gross
electricity generation ratio for all thermal power plants is acceptable.
The following table summarizes the calculation of net electricity generation from gross electricity
generation distribution by primary energy resources and net/gross electricity generation ratio for all
system.
Table 22. Net Electricity Generation Calculation by Primary Energy Resources for Turkey for the 5-year
period of [2007 – 2011]
Gross & Net Generations and Percentages of Fuel Types and Primary Energy Resources (Unit: GWh)
Years
5-Year
Percentag
e
94,041.1
9.17%
5-Year
Total
2007
2008
2009
2010
2011
15,136.2
15,857.5
16,595.6
19,104.3
27,347.5
Lignite
38,294.7
41,858.1
39,089.5
35,942.1
38,870.4
194,054.8
18.92%
Total Coal
53,430.9
57,715.6
55,685.1
55,046.4
66,217.9
288,095.8
28.10%
6,469.6
7,208.6
4,439.8
2,143.8
900.5
21,162.3
2.06%
13.3
266.3
345.8
4.3
3.1
632.8
0.06%
0.0
0.0
0.4
0.0
0.0
0.4
0.00%
43.9
43.6
17.6
31.9
0.0
137.0
0.01%
6,526.8
7,518.5
4,803.5
2,180.0
21,932.4
2.14%
95,024.8
98,685.3
96,094.7
98,143.7
491,996.1
47.98%
213.7
219.9
340.1
457.5
903.6
104,047.
6
469.2
1,700.5
0.17%
Fuel-Oil
Diesel Oil
LPG
Naphtha
Natural Gas
46
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2011/uretim%20tuketim(22-45)/40(06-11).xls
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2011/uretim%20tuketim(22-45)/33(84-11).xls
48
http://www.pserc.wisc.edu/documents/publications/special_interest_publications/EPRI_Electricity_Use_Report_Final_1024651.
pdf, pp. 2-6 – 2-14.
49
ftp://ftp.eia.doe.gov/electricity/epatech.pdf, pp 2 – 4.
47
UNFCCC/CCNUCC
Page 42
155,196.
2
36,361.9
164,139.
3
34,278.7
156,923.
4
37,889.5
155,827.
6
55,380.1
171,638.
3
57,756.8
Hydro
35,850.8
33,269.8
35,958.4
51,795.5
511.1
1,008.9
1,931.1
162.4
191,558.
1
183,339.
7
95.71%
36,361.9
155,196.
2
34,801.9
148,537.
8
Thermal
Geothermal + Wind
Geothermal
Wind
General Total (Net)
Net / Gross Ratio
Gross - Low-Cost/Must-Run
Gross Excluding Low-Cost/Must-Run (Thermal)
Net - Low-Cost/Must-Run
Net Excluding Low-Cost/Must-Run (Thermal)
803,724.8
78.38%
221,667.0
21.62%
52,338.6
209,213.1
20.40%
3,584.6
5,418.2
12,453.9
1.21%
435.7
668.2
694.3
1,960.7
0.19%
846.5
198,418.
0
189,761.
9
95.64%
1,495.4
194,812.
9
186,619.
3
95.79%
2,916.4
211,207.
7
203,046.
1
96.14%
4,723.9
9,982.1
229,395.
1,025,391.8
1
217,557.
980,324.7
7
94.84%
95.60%
0.97%
34,278.7
164,139.
3
32,783.3
156,978.
6
37,889.5
156,923.
4
36,295.9
150,323.
4
55,380.1
155,827.
6
53,240.1
149,806.
0
57,756.8
171,638.
3
54,776.4
162,781.
3
100.00%
95.60%
221,667.0
21.62%
803,724.8
78.38%
211,897.5
768,427.2
The operating margin emission factor was calculated using the above assumptions, data and
formulations. The details are in the Section “B.6.3. Ex ante calculation of emission reductions”.
Step 5: Calculate the build margin (BM) emission factor
For this step, Option I indicated in paragraph 68 of the Tool was chosen and the build margin emission
factor is calculated ex ante based on the most recent information available at the time of writing this
report.
Power plant based generation data is unavailable for Turkish National Grid. However, plant based
generation capacity data is available in annually published Capacity Projection Reports of TEIAS 50. The
latest of these reports, “Turkish Electrical Energy 10-Year Generation Capacity Projection Report 2012 –
2021 (with definitive values of year 2011)”4 was used as the reference for build margin emission
calculation.
In this report, there are “Project Generation Capacity” and “Firm Generation Capacity” for each power
plant. Project Generation Capacity is the value written on the generation licence given by EMRA for each
power plant, and indicates the generation that could be achieved under ideal conditions. Firm Generation
Capacity reflects the real generation capacity, taking into account various parameters that could affect the
generation, and mostly based on the actual generations of the previous years. Hence, firm generation
capacities of power plants indicated in this report were selected as the reference generation data for the
build margin emission calculation.
The total firm generation capacity in 2011 is calculated as 266,380.9 GWh 21, a figure higher than total
gross generation of 229,395.1 GWh in 201146,47. This is expected, since the full annual firm generation
capacities of power plants commissioned in 2011 have been taken into account. Since the real
contribution of firm generation capacities of power plants commissioned in 2011 to real gross generation
in 2011 is very hard to calculate, the firm generation capacities of all power plants at the end of 2011 is
assumed as their gross generation in 2011, to calculate the build margin emission factor calculation. This
is also in line with the logic behind the build margin emission factor calculation, that is, this assumption
reflects the impact of power plants that started to supply electricity to the grid most recently better.
50
http://www.teias.gov.tr/KapasiteProjeksiyonu.aspx
UNFCCC/CCNUCC
Page 43
The “Turkish Electrical Energy 10-Year Generation Capacity Projection Report 2012 – 2021 (with
definitive values of year 2011)” gives the definitive situation of the Turkish Energy Generation System
as at the end of 2011. At this date, there were 643 power plants in Turkey2,3,4. 618 of these were listed
namely, 25 of them under the categorisation of “Others” in 5 different places in the Annex 1 of the
report21. So, since it is impossible to specify the names and commissioning dates of the power plants in
the “Others” category, these were excluded in the build margin emission factor calculation.
Capacity additions of retrofits of power plants were selected by comparing the installed capacity values
and fuel types given in the capacity projection reports for different years50, and explanations given in
energy investment data of Ministry of Energy and Natural Resources of Turkey 51 , which includes
commissioning dates of all power plants in Turkey beginning from 2003.
CDM-VER project activities in Turkey at the end of 2011 were specified by using the registry web sites
of emission reduction standards used in Turkey, i.e. Gold Standard (GS), Verified Carbon Standard
(VCS), and VER+ standards 52,53,54,55. A total of 125 power plants have been specified as CDM-VER
Projects in Turkey listed in the registry sites of these standards.
The commissioning of power plants in Turkey are often made in multiple stages, as allowed in the
“Electrical Installations Acceptance Bylaw”56. The rationale of this procedure is mostly to commission
the part or group of the power plant that has been completed and ready to be commissioned without
having to wait for all the power plant to be completed; and not to lose revenues from electricity sales in
this period. These single stages of commissionings are called “provisional acceptance” and represents the
date on which the electricity generated by the power plant started to be sold.
As a result, these partial commissionings, which are the individual stages of commissioning process
indicated by provisional acceptances, have to be taken into account to calculate the build margin
emission factor correctly. For this reason, each single partial commissioning of a power plant was
considered as a separate power unit.
The project and firm generation of each power unit was found by multiplying the total project and firm
generation of the power plant by the ratio found by dividing the installed capacity of the power unit by
that of the whole power plant.
The dates of commissionings, or power units, were taken from Capacity Projection Reports of TEIAS50
and Energy Investment Data of Ministry of Energy51. The commissionings were sorted by their dates
beginning from the newest to the oldest to identify the two sets of power units SET5-units, and SET20 per
cent, according to paragraph 71 on the page 20 of the Tool.
The calculation of build margin emission factor calculation is done according to the paragraph 73 and
73, on pages 22 – 23 of the Tool:
51
http://www.enerji.gov.tr/index.php?dil=tr&sf=webpages&b=yayinlar_raporlar&bn=550&hn=&id=3273
http://goldstandard.apx.com/
53
http://www.markit.com/sites/en/products/environmental/markit-environmental-registry-public-view.page
54
https://vcsprojectdatabase2.apx.com/myModule/Interactive.asp?Tab=Projects&a=1
55
http://www.netinform.de/KE/Wegweiser/Ebene1_Projekte2.aspx?Ebene1_ID=49&mode=4
56
http://www.resmigazete.gov.tr/arsiv/22280.pdf, pp. 2 – 37.
52
UNFCCC/CCNUCC
“73.
Page 44
The build margin emissions factor is the generation-weighted average emission factor (t
CO2/MWh) of all power units m during the most recent year y for which electricity generation
data is available, calculated as follows:
EFgrid ,BM , y 

m
EG m , y  EFEL ,m, y

m
EG m, y
Equation (13)
Where:
EFgrid,BM,y
= Build margin CO2 emission factor in year y (t CO2/MWh)
EGm,y
= Net quantity of electricity generated and delivered to the grid by
power unit m in year y (MWh)
= CO2 emission factor of power unit m in year y (t CO2/MWh)
= Power units included in the build margin
= Most recent historical year for which electricity generation data is
available
EFEL,m,y
m
y
74.
The CO2 emission factor of each power unit m (EFEL,m,y)should be determined as per the
guidance in Step 4 section 6.4.1 for the simple OM, using Options A1, A2 or A3, using for y the
most recent historical year for which electricity generation data is available, and using for m the
power units included in the build margin.”
Since the power plant based data of emission factors and consumed fuels are not available, but
generations and fuel types are available for the sample group of power units m used to calculate the
build margin, only Option A2 of the Simple OM method is convenient for a calculation. So, emission
factor for power plants for each fuel is calculated as indicated in the following sub-paragraph (b) of
paragraph 44 on page 12 of the Tool:
“(b) Option A2 - If for a power unit m only data on electricity generation and the fuel types used is
available, the emission factor should be determined based on the CO2 emission factor of the fuel type
used and the efficiency of the power unit, as follows:
EFEL ,m, y 
EFCO2 ,m ,i , y  3.6
 m, y
Equation (3)
Where:
EFEL,m,y
EFCO2,m,i,y
ηm,y
m
y
= CO2 emission factor of power unit m in year y (t CO2/MWh)
= Average CO2 emission factor of fuel type i used in power unit m in
year y (t CO2/GJ)
= Average net energy conversion efficiency of power unit m in year y
(ratio)
= All power units serving the grid in year y except low-cost/must-run
power units
= The relevant year as per the data vintage chosen in Step 3
For the average emission factor of fuel types, the emission factors published by IPCC32 were taken as
reference, and the lower limits of the 95 percent confidence intervals were used, as in the calculation of
Operating Margin Emission Factor.
UNFCCC/CCNUCC
Page 45
For the average net energy conversion efficiency of the power units for each fuel type, Table 1 in
Appendix 1 on page 33 of the Tool was taken as reference, as indicated in the table below.
Table 23. IPCC Default Efficiency Factors for Grid Power Plants
Appendix 1. Default efficiency factors for power plants
- Table 1. Grid power plants
Grid Power Plant
Old Units
(before
Generation Technology
and in
2000)
Coal
Subcritical
37.0%
Supercritical
Ultra-Supercriticial
IGCC
FBS
35.5%
CFBS
36.5%
PFBS
Oil
Steam turbine
37.5%
Open cycle
30.0%
Combined cycle
46.0%
Natural gas
Steam turbine
37.5%
Open cycle
30.0%
Combined cycle
46.0%
New
Units
(after
2000)
39.0%
45.0%
50.0%
50.0%
40.0%
41.5%
39.0%
39.5%
46.0%
37.5%
39.5%
60.0%
For most of the power plants included in the build margin emission factor calculation, power-plant
specific data could not be found. For these, the data in the above table was used and maximum
applicable values considering conservativeness were taken. The values for new units (after 2000) were
used.
However, for the thermal power plants using imported coal that were in the build margin emission
calculation set, the efficiency data had been able to be found 57. For these, generation-weighted average
efficiency was calculated and this value is used in the build margin emission factor calculation, as
indicated in the following table:
Table 24. Efficiency Factors for Power Plants Using Imported Coal as the Fuel in the Sample Group
used in the Build Margin Emission Calculation
57
Panel about “Coal-Fired Power Plants and Investment Models”, Middle East Technical University Alumni Association Visnelik
Facility, 23 February 2013 / Saturday / 13:30, Presentation given by Muzaffer BASARAN,
http://www.odtumd.org.tr/dosyaArsivi/Etkinlik/muzaffer_basaran_odtu_komur_santral_230213.pptx, slides 31 – 40.
UNFCCC/CCNUCC
Fuel /
Legal
Energy POWER PLANT NAME
Status
Source
IPP
IC
IPP
IC
IPP
IC
IPP
IC
IPP
IC
IPP
BEKİRLİ TES (İÇDAŞ
ELEKT.)
EREN ENERJİ
ELEK.ÜR.A.Ş.
EREN ENERJİ
ELEK.ÜR.A.Ş.
EREN ENERJİ
ELEK.ÜR.A.Ş.
Page 46
Firm
Installed Generation
Capacity
Capacity
MW
(year 2012)
GWh
Commissioning
Date
Location
(Province)
Efficiency
Firm
Generation
x Efficiency
600.000
4,320.0
2011-12-15 Canakkale
41.5%
1,792.80
600.000
4,005.9
2010-12-29 Zonguldak
42.0%
1,682.47
600.000
4,005.9
42.0%
1,682.47
160.000
1,068.2
41.0%
437.98
İÇDAŞ ÇELİK
135.000
961.7
35.0%
336.58
IC
İÇDAŞ ÇELİK
135.000
961.7
35.0%
336.58
IC
TOTAL
2,230.0
40.9%
6,268.9
15,323.3 Average Efficiency
This result is compatible with the information given by IEA (International Energy Agency), in which it
was stated that supercritical pulverised (SCPC) is the dominant option for new coal fired power plants
and maximum value for generating efficiency of SCPC plants is 46% (lower heating value, LHV), as of
201058.
For the power plants using other types of solid fuels (hard coal, lignite, asphaltite, and waste materials
incinerated), since there are no specific data that could be found, the efficiency factor is assumed as
equal to that of imported coal, and the value that is nearest to the efficiency calculated for power plants
using imported coal in the IPCC Default Efficiency Factors Table (Table 23), that is 41.5 %, was
accepted as the efficiency factor. This is in line with the rule of conservativeness, since generally
efficiency of other types of coal and other solid fuels is expected to be lower than that of imported coal,
which is of higher quality. Also, since the share of other types of solid wastes are very small as
compared to that of imported coal, their effect is minimal.
For natural gas, the maximum value (60.0 %) was. For naphta, biogas, and liquefied petroleum gas
(LPG)
The efficiency factor is accepted as equal to natural gas.
For liquid fuels except naphta, that is fuel oil and diesel oil, the efficiency factor is accepted as the
maximum value in the table, 46 %, according to the rule of conservativeness.
The results were put into the Equation (13) on page 22 of the Tool to calculate the Build Margin
Emission Factor.
Step 6: Calculate the combined margin emissions factor
The calculation of the combined margin (CM) emission factor (EFgrid,CM,y) is done preferring the
Weighted Average CM method, as indicated in paragraphs 77, 78, and 79 in the sub-section 6.6 on page
23 of the Tool.
The weighted average combined margin emission factor calculation is done according to paragraphs 80
and 81 on pages 23 – 24 of the Tool, as follows:
“80.
58
The combined margin emissions factor is calculated as follows:
http://www.iea-etsap.org/web/E-TechDS/PDF/E01-coal-fired-power-GS-AD-gct.pdf, p. 1.
UNFCCC/CCNUCC
Page 47
EFgrid ,CM , y  EFgrid ,OM , y  wOM  EFgrid ,BM , y  wBM
Equation (14)
Where:
EFgrid,BM,y
EFgrid,OM,y
wOM
wBM
81.
=
=
=
=
Build margin CO2 emission factor in year y (t CO2/MWh)
Operating margin CO2 emission factor in year y (t CO2/MWh)
Weighting of operating margin emissions factor (per cent)
Weighting of build margin emissions factor (per cent)
The following default values should be used for wOM and wBM:
(a)
Wind and solar power generation project activities: wOM = 0.75 and wBM = 0.25 (owing to
their intermittent and non-dispatchable nature) for the first crediting period and for
subsequent crediting periods;
(b)
All other projects: wOM = 0.5 and wBM = 0.5 for the first crediting period, and wOM = 0.25
and wBM = 0.75 for the second and third crediting period,6 unless otherwise specified in
the approved methodology which refers to this tool.”
The details are in the Section “B.6.3. Ex ante calculation of emission reductions”.
B.6.2. Data and parameters fixed ex ante
Data / Parameter
EGgross,y
Unit
GWh
Description
Total quantity of gross electricity generation of power plants connected to
the grid including low-cost/must-run power plants in year y for years in
the 5-year period of [2007 – 2011].
Source of data
Official data from TEIAS (Turkish Electricity Transmission Company),
the responsible authority for the operation of Turkish National Grid.
Value(s) applied
See Section B.6.3 and/or Appendix 4 for details.
Choice of data
or
Measurement methods
and procedures
Official data. According to the regulations regarding the Turkish
Statistical Institute, the state organization responsible for the statistical
affairs in the Republic of Turkey, TEIAS is the official source of data for
energy59,60.
Purpose of data
Calculation of baseline emissions.
Additional comment
59
http://www.turkstat.gov.tr/rip/rip.pdf
http://www.tuik.gov.tr/rip/temalar/4_3.html
60
UNFCCC/CCNUCC
Page 48
Data / Parameter
EGgross,i,y
Unit
GWh
Description
Quantity of gross electricity generation of power plants using fuel type /
utilizing primary energy source i connected to the grid including lowcost/must-run power plants in year y for years in the 5-year period of
[2007 – 2011].
Source of data
Value(s) applied
See Section B.6.3 and/or Appendix 4 for details
Choice of data
or
Measurement methods
and procedures
energy59,60.
Since power plant based data is unavailable, the amounts of generation
for group of power plants using the same fuel type / utilizing the same
primary energy source i were used.
Purpose of data
Additional comment
Data / Parameter
EG,y
Unit
GWh
Description
Total net quantity of electricity generation of power plants connected to
the grid, not including low-cost/must-run power plants in year y for years
in the 5-year period of [2007 – 2011].
Source of data
Value(s) applied
Choice of data
or
Measurement methods
and procedures
energy59,60.
Purpose of data
Additional comment
-
UNFCCC/CCNUCC
Page 49
Data / Parameter
EGi,y
Unit
GWh
Description
Net quantity of electricity generation of power plants using fuel type i
connected to the grid, not including low-cost/must-run power plants in
year y for years in the 5-year period of [2007 – 2011].
Source of data
Value(s) applied
Choice of data
or
Measurement methods
and procedures
energy59,60.
Since power plant based and fuel/primary energy source specific data is
not available, net electricity generation of each group of power plants
using the same fuel i for that year y was calculated applying the same
net/gross electricity generation ratio for that year y to gross generation of
each group of power plants using the same fuel i in that year y.
Purpose of data
Additional comment
-
Data / Parameter
EGimport,y
Unit
GWh
Description
Quantity of electricity imports in year y for years in the 5-year period of
[2007 – 2011].
Source of data
Value(s) applied
Choice of data
or
Measurement methods
and procedures
energy59,60.
Purpose of data
Additional comment
-
UNFCCC/CCNUCC
Page 50
Data / Parameter
FCi,y
Unit
ton (liquid and solid fuels) / 103 m3 (gaseous fuels)
Description
Amount of fuels consumed in thermal power plants in Turkey by fuel
type i in year y for years in the 5-year period of [2007 – 2011].
Source of data
Value(s) applied
Choice of data
or
Measurement methods
and procedures
energy59,60.
Purpose of data
Additional comment
-
Data / Parameter
NCVi,y
Unit
TJ/Gg, GJ/ton
Description
Net calorific value of fuel type i consumed by thermal power plants in
year y in the 5-year period of [2007 – 2011]
Source of data
Value(s) applied
Choice of data
or
Measurement methods
and procedures
energy59,60. The net calorific values are calculated using the amount of
fuels used1 and the heating values of the fuels31.
Purpose of data
Additional comment
In order for all the units of consumed fuels to be compatible with each
other, the unit of natural gas consumed should be converted to mass
units. Also, heating values given by TEIAS, which are expressed in [cal],
must be converted into [J]. For this purpose, conversion factors given in
International Energy Agency were used 33,34,35. Natural gas density was
accepted as 0.692 kg/m3, and 1 cal was assumed to be equal to 4.1868 J.
UNFCCC/CCNUCC
61
Page 51
Data / Parameter
EFCO2,i,y
Unit
kg/TJ
Description
Default CO2 emission factors of fossil fuel type i for combustion.
Source of data
IPCC default values at the lower limit of the uncertainty at a 95 per cent
confidence interval as provided in table 1.4 of Chapter1 of Vol. 2
(Energy) of the 2006 IPCC Guidelines on National GHG Inventories,
pages 1.23 – 1.2432.
Value(s) applied
See Section B.6.1, B.6.3 and/or Appendix 4 for details.
Choice of data
or
Measurement methods
and procedures
Country or project specific data are not available for power plants using
fossil fuels in Turkey. Hence, IPCC default emission factors have been
used according to the Tool (Section 7, page 29) and the UNFCCC CDM
“Guidance on IPCC Default Values”61.
Purpose of data
Additional comment
-
Data / Parameter
ηi,y
Unit
Dimensionless (% ratio)
Description
Average net energy conversion efficiency of power units using fuel i in
year y.
Source of data
For power plants using imported coal as fuel, the data given in
presentation by Muzaffer Basaran in Panel about “Coal-Fired Power
Plants and Investment Models”, in Middle East Technical University
Alumni Association Visnelik Facility, on 23 February 201357 were used.
For other types of fuels, the values in Table 1 in Appendix 1 of the Tool
were applied.
Value(s) applied
See Section B.6.1, B.6.3 and/or Appendix 4 for details.
Choice of data
or
Measurement methods
and procedures
Power plant and/or fuel type specific of net energy conversion
efficiencies are impossible or very hard to find. Hence, the data available
for imported coal using power plants from a panel conducted at the
alumni association of a technical university (Middle East Technical
University) were used. For the other fuel types, default efficiency factors
for power plants in Appendix 1 of the Tool were selected taking the
conservativeness rule into account.
Purpose of data
Additional comment
-
http://cdm.unfccc.int/Reference/Guidclarif/meth/meth_guid16_v01.pdf
UNFCCC/CCNUCC
Page 52
Data / Parameter
CAPBM
Unit
Power Plant Name, Installed Capacity [MW], Electricity Generation
[GWh], Commissioning Date [YYYY-MM-DD]
Description
Capacity additions forming the sample group of power units used to
calculate the build margin.
Source of data
TEIAS (Turkish Electricity Transmission Company) Capacity Projection
Reports and Ministry of Energy and Natural Resources of Republic of
Turkey Energy Investment Data50,51. Operational power plants at the end
of 2011 were selected as the reference group 21.
Value(s) applied
See Section B.6.3 and Appendix 4.
Choice of data
or
Measurement methods
and procedures
Annual electricity generation of the project electricity system AEGtotal was
determined excluding power units registered as CDM project activities
and capacity additions from retrofits of power plants. Since generation
data for individual power plants are not available, but firm generation
capacities of individual power plants are available, firm generation
capacities were used as the actual generations21. Every single
commissioning of each power plant is assumed as a power unit. These
power units are sorted by date from the newest to the oldest. The newest
5 power units, SET5-units, their electricity generation AEGSET-5-units, and the
group of power units that started to supply electricity to the grid most
recently and that comprise 20 per cent of AEGtotal, SET20 per cent, and
their electricity generation AEGSET-20 per cent were identified.
Purpose of data
Additional comment
-
B.6.3. Ex ante calculation of emission reductions
a) Operating Margin Emission Factor Calculation:
The calculation was performed according to the Option B of the Simple OM method of the Tool. Only
grid connected power plants were included in the project electricity system. Ex-ante option was chosen,
and a 3-year generation-weighted average, based on the most recent data available at the time of
submission, was taken. The relevant reference period corresponds to the 3 year period of [2009 – 2011].
The gross electricity generations of these years by primary energy sources are as follows 62,63,64:
62
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2011/uretim%20tuketim(22-45)/44.xls
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2010/front%20page%202010-çiçek%20kitap/uretim%20tuketim(2245)/44.xls
64
http://www.teias.gov.tr/TürkiyeElektrikİstatistikleri/istatistik2009/41.xls
63
UNFCCC/CCNUCC
Page 53
Table 25. Gross Electricity Generations of Turkish Electricity System by Primary Energy Sources in
Years [2009 – 2011]
Gross Generations by Fuel Types and Primary Energy Resources in [2009 - 2011] (Unit: GWh)
Lignite
Total Coal
Fuel-Oil
Diesel Oil
LPG
Naphtha
Natural Gas
Thermal
Hydro
Geothermal + Wind
Geothermal
Wind
Years
2009
2010
2011
16,595.6 19,104.3 27,347.5
39,089.5 35,942.1 38,870.4
55,685.1 55,046.4 66,217.9
4,439.8
2,143.8
900.5
345.8
4.3
3.1
0.4
0.0
0.0
17.6
31.9
0.0
4,803.5
2,180.0
903.6
96,094.7 98,143.7 104,047.6
340.1
457.5
469.2
156,923.4 155,827.6 171,638.3
37,889.5 55,380.1 57,756.8
35,958.4 51,795.5 52,338.6
1,931.1
3,584.6
5,418.2
435.7
668.2
694.3
1,495.4
2,916.4
4,723.9
194,812.9 211,207.7 229,395.1
3-Year Total
63,047.4
113,901.9
176,949.3
7,484.1
353.2
0.4
49.5
7,887.2
298,286.0
1,266.9
484,389.4
151,026.4
140,092.5
10,933.9
1,798.3
9,135.6
635,415.7
Net electricity generation is only available for the whole project electricity system, not for each fuel type
or primary energy source47:
Table 26. Gross and Net Electricity Generations of Turkish Electricity System in Years [2009 – 2011]
Gross and Net Generations in [2009 - 2011] (Unit: GWh)
Primary Energy Resource or Fuel
Type
General Total (Net)
Net / Gross Ratio
Years
2009
2010
2011
194,812.9 211,207.7 229,395.1
186,619.3 203,046.1 217,557.7
95.79%
96.14%
94.84%
3-Year Total
635,415.7
607,223.1
95.56%
The corresponding net/gross ratio of each year was applied to gross generations of each primary energy
source to find the net generation of group of power plants utilizing that primary energy source, with
low-cost/must-run power plants excluded:
Table 27. Net Electricity Generations of Turkish Electricity System by Primary Energy Sources,
Excluding Low-Cost/Must-Run Power Plants, (Thermal Power Plants) in Years [2009 – 2011]
Net Electricity Generation Excluding
Low-Cost/Must-Run (Thermal Power
Plants) (Unit: GWh)
Years
2009
2010
2011
3-Year
Total
UNFCCC/CCNUCC
Lignite
Fuel Oil
Diesel oil
LPG
Naphtha
Natural Gas
Page 54
15,897.6
37,445.4
4,253.0
331.3
0.4
16.8
92,053.1
325.8
150,323.4
18,366.0
34,553.2
2,061.0
4.1
0.0
30.7
94,351.2
439.8
149,806.0
25,936.3
36,864.6
854.0
2.9
0.0
0.0
98,678.5
445.0
162,781.3
60,199.9
108,863.2
7,168.1
338.3
0.4
47.5
285,082.7
1,210.7
462,910.7
Fuel consumptions of thermal power plants were also taken from TEIAS statistics 1. The amount of
natural gas was converted from volume to mass units using the density value of 0.692 kg/m 3, as
explained in section B.6.1.
Table 28. Fuel Consumption of Thermal Power Plants by Fuel Type, in Years [2009 – 2011]
Generation Excluding Low-Cost/MustRun (Unit: Ton)
Lignite
Fuel Oil
Diesel oil
LPG
Naphtha
Natural Gas
Years
3-Year Total
2009
6,621,177.0
63,620,518.0
1,594,321.0
180,857.0
111.0
8,077.0
14,515,664.6
86,540,725.6
2010
7,419,703.0
56,689,392.0
891,782.0
20,354.0
0.0
13,140.0
15,072,939.7
80,107,310.7
2011
10,574,434.0
61,507,310.0
531,608.0
15,047.0
0.0
0.0
15,779,535.9
88,407,934.9
24,615,314.0
181,817,220.0
3,017,711.0
216,258.0
111.0
21,217.0
45,368,140.2
255,055,971.2
Heating values of fuels consumed in power plants were also taken from the TEIAS statistics 31. These
values were in [Tcal] units, and were converted into [TJ], using the ratio 1 cal = 4.1868 J, given by
IEA33,34,35.
Table 29. Heating Values of Fuels Consumed in Thermal Power Plants in Turkey, in Years [2009 –
2011]
Heating Values of Fuels Consumed in
Thermal Power Plants (Unit: TJ)
Lignite
Fuel Oil
Diesel oil
LPG
Naphtha
Natural Gas
Years
2009
147,081.2
408,847.5
63,471.5
7,662.8
5.2
352.5
779,857.7
1,407,278.4
2010
165,573.3
404,239.7
35,877.2
877.1
0.0
440.2
814,279.2
1,421,286.7
The corresponding net calorific values (NCV) were found as follows:
2011
241,022.6
448,864.9
22,105.8
649.3
0.0
0.0
846,002.0
1,558,644.5
3-Year Total
553,677.2
1,261,952.1
121,454.5
9,189.1
5.2
792.7
2,440,138.9
4,387,209.6
UNFCCC/CCNUCC
Page 55
Table 30. Net Calorific Values of Fuels Consumed in Thermal Power Plants in Turkey, in Years [2009
– 2011]
Net Calorific Values of Fuels
Consumed in Thermal Power Plants
(Unit: TJ/Gg)
Years
2009
2010
22.2
6.4
39.8
42.4
46.5
43.6
53.7
16.3
Lignite
Fuel Oil
Diesel oil
LPG
Naphtha
Natural Gas
2011
22.3
7.1
40.2
43.1
0.0
33.5
54.0
17.7
22.8
7.3
41.6
43.2
0.0
0.0
53.6
17.6
Due to the absence of power-plant based or fuel based emission factor data, the lower limit of the 95
percent confidence intervals of IPCC default emission factor values were applied 32, and the emission
factor for electricity imports were assumed as zero:
Table 31. Emission Factors used in the Operating Margin Emission Factor Calculation.
Table 1.4
Emission Factors by Fuel Type
(IPCC Values) (kg/TJ)
Default CO2 Emission Factors
for Combustion (kg/TJ)
Default
Lower
Upper
94,600
89,500
99,700
Lignite
101,000
90,900
115,000
Fuel Oil
77,400
75,500
78,800
Diesel oil
74,100
72,600
74,800
LPG
63,100
61,600
65,600
Naphtha
73,300
69,300
76,300
Natural Gas
56,100
54,300
58,300
0
0
0
Import
The corresponding emissions and Operating Margin Emission Factors were calculated using the above
values:
Table 32. Operating Margin Emission Factor Calculation.
UNFCCC/CCNUCC
Page 56
Operating Margin Emission Factor Calculation
CO2 Emissions (ton)
Lignite
Fuel Oil
Diesel oil
LPG
Naphtha
Natural Gas
Import
Total Emission [ton]
Total Net Electricity Generation,
excluding low-cost/must-run [GWh]
Yearly Emission Factor [tCO2/MWh]
2009-2011 Total Emissions [ton]
2009-2011 Total Net Electricity Gen. [GWh]
2009-2011 OMEF Calculation [tCO2/MWh]
2009
13,163,770.74
37,164,240.90
4,792,096.57
556,318.57
317.74
24,429.94
42,346,272.06
0.00
98,047,446.52
Years
2010
14,818,807.99
36,745,389.26
2,708,730.18
63,674.50
0.00
30,502.68
44,215,362.69
0.00
98,582,467.30
2011
21,571,526.82
40,801,815.79
1,668,984.86
47,138.38
0.00
0.00
45,937,907.18
0.00
110,027,373.03
149,997.58
149,366.19
162,336.32
0.654
0.660
0.678
306,657,286.85
461,700.1
0.664
As a result, the Operating Margin Emission Factor for the selected period was found to be
EFgrid,OM, simple = 0.664 tCO2/MWh.
b) Build Margin Emission Factor Calculation:
Option 1, ex ante based build margin emission factor calculation, was selected.
Capacity additions from retrofits of power plants that could be identified are as follows:
Table 33. Capacity additions from retrofits of power plants that could be identified in commissioned
power units.
Capacity Additions from Retrofit of Power Plants (As at the end 2011)
Fuel /
No Energy
Source
1
2
3
4
5
6
7
8
NG
NG
NG
NG
NG
NG
NG
NG
POWER PLANT NAME
AKBAŞLAR
AMYLUM NİŞASTA (Adana)
DENİZLİ ÇİMENTO
ISPARTA MENSUCAT
PAKGIDA (Düzce-Köseköy)
PAKMAYA (Köseköy)
PAKMAYA (Köseköy)
KAREGE ARGES
Installed
Capacity
MW
3.960
6.200
14.000
4.300
4.800
4.800
2.100
26.280
Firm
Generation
Capacity
(year 2012)
GWh
30.06
34.69
113.00
33.00
38.26
38.26
16.74
209.09
Commissioning
Date
Location
(Province)
2003-09-13 Bursa
Adana
2006-05-04 Denizli
Isparta
Duzce
Kocaeli
2003-07-02 Kocaeli
2003-07-30 Izmir
GENERAL TOTAL
66.4
513.1
Abbreviations: FS: Fuel Switch, NG: Natural Gas, FO: Fuel Oil, LPG: Liquefied Petroleum Gas
Retrofit Type
FS from FO to NG
FS from FO to NG
FS from FO to NG
FS from FO to NG
FS from LPG to NG
FS from LPG to NG
FS from LPG to NG
FS from FO to NG
UNFCCC/CCNUCC
Page 57
CDM project activities are identified as follows21,52,53,54,55:
Table 34. CDM VER Projects in Turkey as at the end of 2011
No
Fuel /
Energy
Source
Power Plant Name
Installed
Capacity
(MW)
Location
(Province)
Commissioning
Date (First)
Standard
Code /
Number /
Project ID
1
WS
ITC-KA ENERJİ MAMAK
25.4 Ankara
2011-10-14 GS
GS440
2
WS
ITC-KA ENERJİ SİNCAN
5.7 Ankara
2011-04-08 GS
GS675
3
WS
ITC-KA ENERJİ KONYA (ASLIM
BİYOKÜTLE)
5.7 Konya
2011-10-21 GS
GS1016
4
WS
ITC-KA ENERJİ ADANA (BİYOKÜTLE)
11.3 Adana
2011-10-06 GS
GS715
5
WS
ORTADOĞU ENERJİ (KÖMÜRCÜODA)
5.8 Istanbul
2009-07-15 GS
GS707
6
WS
BOLU BEL.ÇÖP (CEV MARMARA)
1.1 Bolu
2011-08-26 GS
GS764
7
WS
KAYSERİ KATI ATIK (HER EN.)
1.6 Kayseri
2011-11-01 GS
GS1061
8
HE
AKIM (CEVİZLİK HES)
91.4 Giresun
2010-05-28 VCS
753
9
HE
ANADOLU ÇAKIRLAR
16.2 Artvin
2009-08-13 GS
GS917
10
HE
ASA EN.(KALE REG.)
9.6 Rize
2010-02-19 GS
GS637
11
HE
AYRANCILAR (MURADİYE ELEK.)
32.1 Van
2011-08-25 GS, VCS
GS729,
577
12
HE
CEYKAR BAĞIŞLI
29.6 Hakkari
2009-05-07 VCS
657
13
HE
BEREKET (KOYULHİSAR)
42.0 Sivas
2009-06-12 VCS
713
14
HE
BEYOBASI (SIRMA)
5.9 Aydin
2009-05-23 VCS
603
15
HE
BEYTEK(ÇATALOLUK HES)
9.5 K.Maras
2010-04-07 GS
GS872
16
HE
BULAM
7.0 Adiyaman
2010-08-10 GS
GS642
17
HE
BURÇBENDİ (AKKUR EN.)
27.3 Adiyaman
2010-11-04 VCS
419
18
HE
CEVHER (ÖZCEVHER)
16.4 Trabzon
2011-01-17 GS
GS688
19
HE
CEYHAN HES (BERKMAN HES-ENOVA)
25.2 Osmaniye
2010-08-28 VCS
810
20
HE
CEYHAN HES (OŞKAN HES-ENOVA)
23.9 Osmaniye
2010-06-03 VCS
810
21
HE
ÇAKIT HES
20.2 Adana
2010-06-01 VCS
685
22
HE
ÇALDERE ELEKTRİK DALAMAN MUĞLA
8.7 Mugla
2008-04-02 VCS
363
23
HE
ÇAMLICA
27.6 Kayseri
2011-04-01 VCS
759
24
HE
DAMLAPINAR(CENAY ELEK.)
16.4 Karaman
2010-07-08 VER+
25
HE
DARCA HES (BÜKOR EL.)
2011-05-26 GS
GS887
26
HE
DEĞİRMENÜSTÜ (KAHRAMANMARAŞ)
38.6 K.Maras
2009-04-16 VCS
565
27
HE
EGEMEN 1 HES (ENERSİS ELEK.)
19.9 Bursa
28
HE
ELESTAŞ YAYLABEL
29
HE
ELESTAŞ YAZI
30
HE
ERİKLİ-AKOCAK REG.(AK EN.)
31
HE
EŞEN-I (GÖLTAŞ)
32
HE
33
HE
34
HE
GÜZELÇAY-I HES(İLK EN.)
35
HE
HAMZALI HES (TURKON MNG ELEK.)
36
HE
HASANLAR (DÜZCE)
37
HE
HİDRO KONTROL (SELİMOĞLU HES)
38
HE
KALE HES
39
HE
KALEN ENER. (KALEN I-II)
8.9 Bilecik
2010-12-28 GS
GS755
5.1 Isparta
2009-09-07 VCS
582
1.1 Cankiri
2009-10-02 VCS
583
82.5 Trabzon
2010-07-29 VCS
535
60.0 Mugla
2011-04-24 VER+
97-1
FEKE 2 (AKKUR EN.)
69.3 Adana
2010-12-24 VCS
534
FİLYOS YALNIZCA HES
14.4 Karabük
2009-09-16 GS
GS618
8.1 Sinop
2010-11-11 GS
GS711
16.7 Kirikkale
2008-11-08 GS
GS633
4.7 Duzce
2011-12-02 GS
GS831
8.8 Trabzon
2010-01-07 GS
GS635
34.1 K.Maras
2010-06-16 VCS
893
31.3 Giresun
2009-06-19 VCS
932
UNFCCC/CCNUCC
Page 58
40
HE
KALKANDERE-YOKUŞLU HES(AKIM EN.)
41
HE
KARASU I HES (İDEAL EN.)
37.9 Rize
2011-01-28 VCS
905
3.8 Erzurum
2011-05-19 GS
GS927
42
HE
43
HE
KARASU 4-2 HES (İDEAL EN.)
10.4 Erzincan
2011-11-24 GS
GS928
KARASU 4-3 HES (İDEAL EN.)
4.6 Erzincan
2011-08-05 GS
GS929
44
HE
KARASU 5 HES (İDEAL EN.)
45
HE
KAR-EN KARADENİZ ELEK.(ARALIK HES)
12.4 Artvin
4.1 Erzincan
2011-08-03 GS
GS929
2010-04-30 GS
46
HE
KAYABÜKÜ HES (ELİTE ELEK.)
14.6 Bolu
GS663
2010-07-21 GS
GS726
47
HE
KIRAN HES (ARSAN EN.)
48
HE
KOZDERE (ADO MAD.)
9.7 Giresun
2011-11-04 GS
GS691
3.1 Antalya
2011-10-08 GS
49
HE
KUMKÖY HES (KUMKÖY EN.)
17.5 Samsun
2011-02-23 VER+
G434
50
HE
TGT EN. LAMAS III-IV
35.7 Mersin
2009-06-05 VCS
51
HE
MARAŞ ENERJİ (FIRNIS)
52
HE
MENGE (ENERJİ-SA)
44.7 Adana
2011-12-22 VCS
578
53
HE
OTLUCA I HES (BEYOBASI)
37.5 Mersin
2011-04-07 VCS
755
54
HE
OTLUCA II HES (BEYOBASI)
6.4 Mersin
2011-07-13 VCS
755
55
HE
ÖZGÜR ELEKTR.AZMAK I
11.8 Mersin
2010-07-10 VCS
554
56
HE
ÖZGÜR ELEKTR.AZMAK II
6.3 Mersin
2010-07-11 VCS
554
57
HE
ÖZTAY GÜNAYŞE
8.3 Trabzon
2009-08-13 GS
GS636
58
HE
PAŞA HES(ÖZGÜR EL.)
8.7 Bolu
2010-06-11 GS
GS681
59
HE
REŞADİYE I HES(TURKON MNG EL.
15.7 Sivas
2010-11-26 GS
GS643
60
HE
REŞADİYE II HES(TURKON MNG EL.
26.1 Tokat
2010-09-17 GS
GS644
61
HE
REŞADİYE III HES(TURKON MNG EL.
22.3 Tokat
2009-11-11 GS
GS645
62
HE
SARAÇBENDİ (ÇAMLICA)
25.5 Sivas
2011-05-06 VCS
758
63
HE
SAYAN (KAREL)
14.9 Osmaniye
2011-11-19 GS
GS730
64
HE
SEFAKÖY (PURE)
33.1 Kars
2011-10-12 VCS
747
65
HE
SELEN EL.(KEPEZKAYA HES)
28.0 Karaman
2010-09-06 VER+
66
HE
SÖĞÜTLÜKAYA (POSOF HES) YENİGÜN
EN.
67
HE
TEKTUĞ-KARGILIK
68
HE
TEKTUĞ-KALEALTI HES
69
HE
TEKTUĞ-KEBENDERESİ
70
HE
TEKTUĞ-ERKENEK
71
HE
YAMAÇ HES (YAMAÇ ENERJİ ÜRETİM
A.Ş.)
72
HE
YEŞİLBAŞ
73
HE
YAPISAN KARICA DARICA
74
HE
75
76
7.2 K.Maras
6.1 Ardahan
726
2008-06-05 VER+
2011-01-20 GS
GS891
23.9 K.Maras
2005-04-24 VCS
264
15.0 Osmaniye
2006-11-30 VCS
111
2007-05-09 VCS
598
2009-11-10 VCS
693
2011-07-20 GS
GS926
5.0 Elazig
13.0 Adiyaman
5.5 Osmaniye
14.0 Sivas
2009-12-04 VCS
806
110.3 Ordu
2011-07-26 VCS
506
YPM ALTINTEPE SUŞEHRİ HES
4.0 Sivas
2007-06-07 VCS
914
HE
YPM BEYPINAR HES
3.6 Sivas
2007-06-07 VCS
914
HE
YPM KONAK HES (SUŞEHRİ/SİVAS)
4.0 Sivas
2007-07-20 VCS
914
77
HE
YPM GÖLOVA
1.1 Sivas
2009-06-10 VCS
914
78
HE
YPM SEVİNDİK
5.7 Sivas
2009-06-09 VCS
914
79
HE
ULUBAT KUVVET TÜN.(AK EN.)
100.0 Bursa
2010-10-22 VCS
536
80
WD
ALİZE ENERJİ (ÇAMSEKİ)
20.8 Canakkale
2009-06-24 GS
GS399
81
WD
ALİZE ENERJİ (KELTEPE)
20.7 Balikesir
2010-04-28 GS
GS437
82
WD
ALİZE ENERJİ (SARIKAYA ŞARKÖY)
28.8 Tekirdag
2009-10-19 GS
GS577
83
WD
AK ENERJİ AYYILDIZ (BANDIRMA)
15.0 Balikesir
2009-07-23 GS
GS634
84
WD
AKDENİZ ELEK. MERSİN RES
33.0 Mersin
2010-03-19 GS
GS753
85
WD
AKRES (AKHİSAR RÜZGAR)
43.8 Manisa
2011-09-23 GS
GS955
86
WD
ANEMON ENERJİ (İNTEPE)
30.4 Canakkale
2007-11-22 GS
GS347
87
WD
ASMAKİNSAN (BANDIRMA-3 RES)
24.0 Balikesir
2010-03-26 GS
GS683
UNFCCC/CCNUCC
88
WD
AYEN ENERJİ (AKBÜK)
89
WD
AYVACIK (AYRES)
90
WD
BAKRAS ELEK.ŞENBÜK RES
Page 59
31.5 Aydin
2009-04-03 GS
GS436
2011-10-23 GS
GS956
15.0 Hatay
2010-04-22 GS
GS733
GS1072,
52-1
5.0 Canakkale
91
WD
BARES (BANDIRMA)
30.0 Balikesir
GS,
2011-08-11
VER+
92
WD
BELEN HATAY
36.0 Hatay
2010-09-02 GS
GS390
93
WD
BERGAMA RES (ALİAĞA RES)
90.0 Izmir
2010-06-16 GS
GS735
94
WD
BORASKO BANDIRMA
60.0 Balikesir
2010-06-30 GS
GS744
95
WD
BOREAS EN.(ENEZ RES)
15.0 Edirne
2010-04-09 GS
GS702
96
WD
ÇANAKKALE RES (ENERJİ-SA)
29.9 Canakkale
2011-05-06 GS
GS906
97
WD
ÇATALTEPE (ALİZE EN.)
16.0 Balikesir
2011-04-19 GS
GS574
98
WD
DOĞAL ENERJİ (BURGAZ)
14.9 Canakkale
2008-05-08 GS
GS439
66
99
WD
DENİZLİ ELEKT. (Karakurt-Akhisar)
10.8 Manisa
VCS,
2007-05-28
VER+
100
WD
MARE MANASTIR
39.2 Izmir
2007-04-13 GS
GS368
101
WD
MAZI 3
30.0 Izmir
2010-06-18 GS
GS388
102
WD
KİLLİK RES (PEM EN.)
40.0 Tokat
2011-12-17 GS
GS947
103
WD
KORES KOCADAĞ
15.0 Izmir
2009-12-23 GS
GS601
104
WD
KUYUCAK (ALİZE ENER.)
25.6 Manisa
2010-12-09 GS
GS576
105
WD
ROTOR (OSMANİYE RES-GÖKÇEDAĞ
RES)
135.0 Osmaniye
2010-10-15 GS
GS474
106
WD
BAKİ ELEKTRİK ŞAMLI RÜZGAR
114.0 Balikesir
2011-11-13 GS
GS351
107
WD
DATÇA RES
29.6 Mugla
2009-12-24 GS
GS438
108
WD
ERTÜRK ELEKT. (ÇATALCA)
60.0 Istanbul
2008-12-27 GS
GS367
109
WD
İNNORES ELEK. YUNTDAĞ
52.5 Izmir
2011-09-27 GS
GS352
110
WD
LODOS RES (TAŞOLUK)KEMERBURGAZ
24.0 Istanbul
2008-08-20 GS
GS503
111
WD
SARES (GARET ENER.)
22.5 Canakkale
2011-03-10 GS
GS963
112
WD
SAYALAR RÜZGAR (DOĞAL ENERJİ)
34.2 Manisa
2009-09-06 GS
GS369
30.0 Hatay
VCS,
2010-03-12
VER+
553
113
WD
SEBENOBA (DENİZ ELEK.)SAMANDAĞ
114
WD
SEYİTALİ RES (DORUK EN.)
115
WD
SOMA RES
116
WD
117
WD
118
30.0 Izmir
2011-07-22 GS
GS578
116.1 Manisa
2011-12-09 GS
GS398
SOMA RES (BİLGİN ELEK.)
90.0 Manisa
2010-11-11 GS
GS655
SUSURLUK (ALANTEK EN.)
45.0 Balikesir
2011-05-20 GS
GS854
WD
ŞAH RES (GALATA WIND)
93.0 Balikesir
2011-07-29 GS
GS905
119
WD
TURGUTTEPE RES (SABAŞ ELEK.)
24.0 Aydin
2011-03-04 GS
GS610
120
WD
ÜTOPYA ELEKTRİK
30.0 Izmir
2010-09-03 GS
GS672
121
WD
ZİYARET RES
57.5 Hatay
2011-11-24 GS
GS617
122
GT
MENDERES JEOTERMAL
8.0 Aydin
2006-05-10 VCS
120
123
GT
MENDERES JEOTERMAL DORA-2
9.5 Aydin
2010-03-26 GS
GS445
124
GT
TUZLA JEO.
7.5 Canakkale
2010-01-13 GS
GS353
AYDIN GERMENCİK JEO.(MAREN
125
GT
20.0 Aydin
2011-11-11 GS
GS861
MARAŞ)
Abbreviations: WD: Wind, HE: Hydroelectric, WS: Waste, GT: Geothermal, GS: Gold Standard, VCS: Verified Carbon Standard
The remaining power units constitute the sample group used to calculate the build margin emission
calculation. There are 639 power units in this group. Complete list of this sample group is in the
Appendix 4 of this report.
These power units in the sample group were sorted by date from the newest to the oldest. The newest 5
power units, SET5-units, were identified as follows:
UNFCCC/CCNUCC
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Table 35. The set of five power units, excluding power units registered as CDM project activities, that
started to supply electricity to the grid most recently (SET5-units)
Fuel /
No Energy
Source
1 NG
2 NG
3 NG
4 IC
5 HE
POWER PLANT NAME
TİRENDA TİRE
AKSA AKRİLİK KİMYA
(İTH.KÖM.+D.G)
ALİAĞA Çakmaktepe Enerji
BEKİRLİ TES (İÇDAŞ ELEKT.)
SARIKAVAK (ESER)
Firm
Generatio
Installed
n Capacity
Capacit
(year
y (MW)
2012)
(GWh)
58.400
410.0
25.000
175.0
8.730
600.000
8.100
65.7
4,320.0
24.0
Commissionin Location
g Date
(Province)
2011-12-30 Izmir
2011-12-30 Yalova
2011-12-29 Izmir
2011-11-25 Mersin
Total
700.2
4,994.7
AEGSET-5-units
4,994,736 MWh
Abbreviations: NG: Natural Gas, IC: Imported Coal, HE: Hydroelectric
Hence, electricity generation of SET5-units is found to be AEGSET-5-units = 4,994,736 MWh.
The total generation of the sample group of power units used to calculate is AEGtotal = 256,636,382
MWh.
20 % of this value is AEGSET-=20 per cent = 51,327,276 MWh. When sorted from the newest to the oldest,
the cumulative firm generation amount up to and including the 204th power unit in the list, Aksa Enerji
(Antalya) Natural Gas Power Plant, with an installed capacity of 46,7 MW and firm generation capacity
of 324.9 GWh, which was commissioned on 29/12/2008, gives us an firm generation amount of
51,589,558 MWh, and satisfies the condition of SET20 per cent.
Hence electricity generation of SET20 per cent is found to be AEGSET-20 per cent = 51,589,558 MWh.
Since AEGSET-20 per cent > AEGSET-5-units, and none of the power units in the SET20 per cent started to
supply electricity to the grid more than 10 years ago, it was assumed that SETsample = SET20 per cent.
The generation distribution of SETsample by primary energy sources is as follows:
Table 36. The distribution of sample group used to calculate the build margin (SETsample) by primary
energy sources (fuels consumed)
Energy Source / Fuel
Asphaltite
Biogas
Diesel Oil
Fuel Oil
Geothermal
Hard Coal
Hydroelectric
Imported Coal
Lignite
Installed
Capacity
(MW)
135.0
0.5
0.0
142.3
47.4
0.0
1,866.2
2,230.0
24.4
Firm
Generation
Capacity (year
2012) (GWh)
945.0
3.7
0.0
967.8
313.0
0.0
3,384.5
15,323.3
147.0
UNFCCC/CCNUCC
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Liquefied Petroleum Gas
Natural Gas
Naphta
Wind
Waste
0.0
4,053.7
49.0
0.0
19.8
0.0
30,079.7
277.9
0.0
147.7
Total
8,568.3
51,589.6
These generation values were put into the formulation as explained in the section B.6.1., and the Build
margin emission factor was calculated as shown in the following table:
Table 37. Build Margin Emission Factor Calculation
Energy Source / Fuel
Firm
Assumed
Generation
Emission
Capacity
Factor
(year 2012)
(kg/TJ)
(GWh)
Assumed Calculated
Default
Emission
Efficiency
Factor
(%)
((tCO2/MWh)
Emission
(ton)
945.0
89,500
41.5%
0.776
733,684.3
Biogas
3.7
46,200
60.0%
0.277
1,025.6
Diesel Oil
0.0
72,600
46.0%
0.568
0.0
Fuel Oil
967.8
75,500
46.0%
0.591
571,857.5
Geothermal
313.0
0
0.0%
0.000
0.0
0.0
92,800
41.5%
0.805
0.0
Hydroelectric
3,384.5
0
0.0%
0.000
0.0
Imported Coal
15,323.3
89,500
40.9%
0.788
12,071,339.9
147.0
90,900
41.5%
0.789
115,913.9
0.0
61,600
60.0%
0.370
0.0
30,079.7
54,300
60.0%
0.326
9,799,962.8
277.9
69,300
60.0%
0.416
115,545.0
0.0
0
0.0%
0.000
0.0
147.7
73,300
41.5%
0.636
93,894.7
0.456
23,503,223.7
Asphaltite
Hard Coal
Lignite
Liquefied Petroleum Gas
Natural Gas
Naphta
Wind
Waste
Total / Overall
51,589.6
The calculated Build Margin Emission Factor is EFgrid,BM,y = 0.456 tCO2/MWh.
c) Combined Margin Emission Factor Calculation:
Combined Margin Emission Factor calculation was done according to the tool as explained the section
B.6.1., by using Weighted Average CM method, with weightings wOM = 0.75 and wBM = 0.25, since the
project activity is a wind farm:
EFgrid ,CM , y  EFgrid ,OM , y  wOM  EFgrid ,BM , y  wBM
Equation (14)
EFgrid,CM,y = 0.664 * 0.75 + 0.456 * 0.25 = 0.612
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The Combined Margin Emission Factor is found to be EFgrid,CM,y = 0.612 tCO2/MWh.
d) Emission Reduction Calculation:
Emission reduction calculation for the first crediting period was done according to the Methodology, as
indicated in section B.6.1., as follows:
ERy = BEy – PEy – LEy
Where:
ERy
BEy
PEy
LEy
=
=
=
=
Emission reductions in year y (t CO2/yr)
Baseline emissions in year y (t CO2/yr)
Project emissions in year y (t CO2/yr)
Leakage emissions year y (t CO2/yr)
Since no leakage emissions are considered by the Methodology, and the project emissions are assumed
as zero as explained in the section B.6.1., we found that the emission reductions is equal to the baseline
emissions.
ERy = BEy
Baseline emissions are calculated using the formulation indicated on page 8 of the Methodology:
“Baseline emissions
Baseline emissions include only CO2 emissions from electricity generation in fossil fuel fired power
plants that are displaced due to the project activity. The methodology assumes that all project electricity
generation above baseline levels would have been generated by existing grid-connected power plants
and the addition of new grid-connected power plants. The baseline emissions are to be calculated as
follows:
BE y  EGPJ , y * EFgrid,CM , y
(4)
Where:
BE y
=
EGPJ , y
=
EFgrid ,CM , y
=
Combined margin CO2 emission factor for grid connected power generation in year y
calculated using the latest version of the “Tool to calculate the emission factor for an
electricity system” (tCO2/MWh)
“
Since the project activity is a greenfield renewable energy power plant, the net electricity generation of
the project activity is calculated according to the rule explained on page 8 – 9 of the Methodology:
“Calculation of EGPJ,y
The calculation of EGPJ,y is different for: (a) greenfield plants, (b) retrofits and replacements; and
(c) capacity additions. These cases are described next.
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(a) Greenfield renewable energy power plants
If the project activity is the installation of a new grid-connected renewable power plant/unit at a site
where no renewable power plant was operated prior to the implementation of the project activity, then:
(5)
EG PJ,y  EG facility, y
Where:
EG PJ,y
=
EG facility, y
=
Quantity of net electricity generation supplied by the project plant/unit to the grid in
year y (MWh/yr)
“
The net annual electricity generation of the project is calculated as EGfacility,y = 194,003 MWh, as
explained in section B.5. The details of this calculation are in both Emission Reduction Calculation and
Investment Analysis spreadsheets as annexes to PDD.
The baseline emission is found as:
BEy = EGPJ,y * EFgrid,CM,y = 194,003 * 0.612 = 118,737 tCO2/yr.
Hence, the emission reductions is ERy = 118,737 tCO2/yr.
For the first year of the crediting period (2012), the net average electricity generation is found to be
145,546 MWh. Hence for 2012, the emission reductions is ER2012 = 89,079 tCO2.
For the last year of the crediting period (2019), the net average electricity generation is found to be
39,864 MWh. Hence for 2019, the emission reductions is ER2019 = 24,398 tCO2.
Total amount of emission reductions for the first crediting period is 825,899 tCO 2. Annual
average over the first crediting period is calculated as 117,986 tCO2/yr. This value is lower than the
estimated amount of annual average GHG emission reductions, due to the partial commissionings in the
first year, causing a lower amount of net electricity generation than the other years.
The details of the emission factor and emission reduction calculations can be found in the emission
reduction calculation spreadsheet as an annex to PDD.
UNFCCC/CCNUCC
B.6.4. Summary of ex ante estimates of emission reductions
Baseline
Project
Year
emissions
emissions
(t CO2e)
(t CO2e)
2012
89,079
0
0
2013
118,737
0
0
2014
118,737
0
0
2015
118,737
0
0
2016
118,737
0
0
2017
118,737
0
0
2018
118,737
0
0
2019
24,398
0
0
Total
825,899
0
0
Total number of 7 years
crediting years
Annual
117,986
0
0
average over the
crediting period
Page 64
Leakage
(t CO2e)
Emission
reductions
(t CO2e)
89,079
118,737
118,737
118,737
118,737
118,737
118,737
24,398
825,899
117,986
UNFCCC/CCNUCC
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B.7. Monitoring plan
B.7.1. Data and parameters to be monitored
Data / Parameter
Unit
Description
Source of data
EGfacility,y
MWh/yr
Quantity of net electricity generation supplied by the project plant/unit to
the grid in year y.
Main source is the data from the web site of PMUM (Market Financial
Settlement Centre) or EPIAS (Energy Markets Operation Company, which
will replace PMUM according to the new Electricity Market Law in
Turkey)65 or any other equivalent state authority responsible for the
operation of national electricity market in Turkey, in case it is enforced by
the law before the end of the first crediting period. These data is based on
the automatic meter reading from the electricity meters of the project
activity, which is performed by TEIAS. This will be the preferred data.
Auxiliary sources will be the monthly electricity protocols signed by
TEIAS officials or electricity sales invoices. These will be used as
confirmative and supportive documents, if necessary.
Value(s) applied
194,003 MWh/yr
Measurement methods There are two groups of electricity meters for two groups of turbines, as
and procedures
indicated in the Section B.3 about the project boundary. Each group of
electricity meters consists of a main meter and a backup meter.
The amount of net electricity generation supplied by the project to the grid
will be calculated by subtracting the amount of electricity drawn from the
grid from the amount fed into the grid for each main electricity meter, and
then adding net electricity generation amount for two main meters.
65
http://www.resmigazete.gov.tr/eskiler/2013/03/20130330-14.htm
UNFCCC/CCNUCC
Monitoring frequency
QA/QC procedures
Page 66
Unless otherwise enforced by the law, or stated in the monitoring reports,
the monitoring will be done on a monthly basis.
TEIAS is responsible for the electricity meter measurements and testing
and control of electricity meters according to “Communiqué on Meters to
be used in the Electricity Market”66, and other related legislation.
TEIAS performs annual periodic tests on every electricity meter, and the
meters are sealed after each test, according to the System Usage Agreement
made between the project proponent and TEIAS67. These seals can only be
broken and re-sealed only by TEIAS authorised personnel.
Apart from the annual tests, the companies producing or importing the
electricity meters are required to guarantee the accuracy and calibration of
the meters66.
The data of PMUM (EPIAS, etc.) uses the electricity measurement data of
TEIAS. This data is reliable since it is only accessible to project owner
apart from PMUM (EPIAS, etc.), and used for invoicing purposes.
Purpose of data
Additional comment
The data of the SCADA system installed within the project activity can
also be used to cross-check the measurements of the electricity meters.
Calculation of baseline emissions
The electricity measurements are used for billing and strictly checked by
project owner and TEIAS. Also, according to the Section III about
Monitoring Methodology of “ACM0002: Consolidated baseline
methodology for grid-connected electricity generation from renewable
sources --- Version 13.0.0”, all data collected as part of monitoring will be
archived electronically and be kept at least two years after the end of the
last crediting period.
B.7.2. Sampling plan
There will be no sampling procedures and all the data related with the electricity measurements will be
used for monitoring purposes.
B.7.3. Other elements of monitoring plan
Operational and Management Structure
Monitoring will be done according to “ACM0002: Consolidated baseline methodology for gridconnected electricity generation from renewable sources --- Version 13.0.0”.
Electricity meters are located at the points indicated in the figure regarding the project boundary and
simplified one-line single diagram of the project activity in the Section B.3 about the project boundary.
At the end of each month, the data about the electricity measurements from PMUM (EPIAS, etc.) will be
collected from the official web site after it has become definite. This data will be copied to spreadsheets
66
http://www.epdk.org.tr/documents/elektrik/mevzuat/teblig/elektrik/sayaclar_hakkinda/Elk_Tblg_Sayaclar.doc
http://eud.teias.gov.tr/SKAM/SKAornek.pdf
67
UNFCCC/CCNUCC
Page 67
to make the calculations easier. The web pages containing the relevant data will be saved as screenshot s
and/or in suitable file formats and be kept for future reference. The monthly electricity meter reading
protocols signed by authorised TEIAS officials will also be kept, if these are available. This will be done
monthly.
The expected verification period is one year. At the end of each verification period, all the documents
collected monthly will be compiled and an emission reduction calculation spreadsheet will be prepared
to show the final results of the emission reductions of the corresponding verification period. This
spreadsheet and documents about electricity generation and the electricity meter readings will be sent to
verifying DOE along with the monitoring report of the corresponding verification period.
Responsibilities and Institutional Arrangements for Data Collection and Archiving
Data collection and archiving will be under the responsibility of the project proponent. Power plant
personnel will send the monthly electricity meter reading protocols and other relevant supportive
documents, if any, to project proponent company headquarters. Power plant personnel will also give
support and help during the site visits of validation, verification and other similar related processes. The
data collection, archiving and communication with the DOEs will be done by the responsible personnel
in the project proponent company headquarters.
SECTION C. Duration and crediting period
C.1. Duration of project activity
C.1.1. Start date of project activity
According to the “Glossary of CDM terms”68 the start date of a project activity is defined as follows:
“In the context of a CDM project activity or CPA, the earliest date at which either the implementation or
construction or real action of a CDM project activity or CPA begins. In the context of a CDM PoA, the
date on which the coordinating/managing entity officially notifies the secretariat and the DNA of their
intention to seek the CDM status or the date of publication of the PoA-DD for global stakeholder
consultation in accordance with the relevant CDM rules and requirements. “
Along with this explanation, the start date of the construction the date at which the building site was
handed over to the contractor company, was assumed as the start date of the project activity.
Therefore, the start date of the project activity is 19/07/2011.
C.1.2. Expected operational lifetime of project activity
20 years
C.2. Crediting period of project activity
C.2.1. Type of crediting period
Renewable, first crediting period.
C.2.2. Start date of crediting period
16/03/2012
68
http://cdm.unfccc.int/Reference/Guidclarif/glos_CDM.pdf
UNFCCC/CCNUCC
Page 68
C.2.3. Length of crediting period
7 years, 0 months.
SECTION D. Environmental impacts
D.1. Analysis of environmental impacts
According to the “Environmental Impact Assessment Regulation”69 the project activity is exempt from
the environmental impact assessment. This is also certified by the exemption decisions granted by the
responsible state authorities70. However, considering that an environmental impact assessment study will
ease the credit and emission reduction related affairs, the project proponent had an accredited consultant
company prepare an environmental study. As a result, two environmental impact assessment reports,
one for the project site, and one for the energy transmission line, have been prepared71.
According to these reports, the project is found to be compatible with regulations related with the
environmental impact assessment, and no harmful effects to the environment could be found. The
details are in the referred EIA reports.
D.2. Environmental impact assessment
No environmental impact assessment is required. In addition, the results of the voluntary environmental
impact assessment study indicate that the project activity has minimal, if any, effects on the environment.
Further information regarding various aspects of environmental impact assessment study can be found
in the EIA reports.
SECTION E. Local stakeholder consultation
E.1. Solicitation of comments from local stakeholders
Since the project activity is intended to be developed as a Gold Standard project, a thorough and detailed
local stakeholder consultation process has been conducted. A Local Stakeholder Consultation meeting
was held on 16/06/2011 in Yahyalı district of Kayseri province, after a comprehensive invitation process.
Detailed information can be found in the Local Stakeholder Consultation Report and the Gold Standard
Passport of the project.
E.2. Summary of comments received
In general, the comments were positive. No significant concerns about the probable negative effects of
the project were raised during the meeting. Detailed information can be found in the Local Stakeholder
Consultation Report and the Gold Standard Passport of the project.
E.3. Report on consideration of comments received
Please refer to Local Stakeholder Consultation Report and the Gold Standard Passport of the project for
detailed information about this issue.
69
http://mevzuat.basbakanlik.gov.tr/Metin.Aspx?MevzuatKod=7.5.12256&sourceXmlSearch=&MevzuatIliski=0
These decisions have been uploaded to the registry site and are available for the DOE. There are three decisions; two for the
project site (a main and a revised one), and one for the energy transmission line.
71
Both of these two EIA reports have been uploaded to the registry site and are available for the DOE.
70
UNFCCC/CCNUCC
Page 69
SECTION F. Approval and authorization
Not available.
-----
UNFCCC/CCNUCC
Page 70
Appendix 1: Contact information of project participants
Organization name
Street/P.O. Box
Building
City
State/Region
Postcode
Country
Telephone
Fax
E-mail
Website
Contact person
Title
Salutation
Last name
Middle name
First name
Department
Mobile
Direct fax
Direct tel.
Personal e-mail
Aksu Temiz Enerji Elektrik Uretim Sanayi ve Ticaret A.S.
Hulya Sokak No: 37, G.O.P.
Ankara
06700
Turkey
+90 312 445 04 64
+90 312 445 05 02
[email protected]
http://www.ayen.com.tr
Hakan Demir
Mr.
Demir
Hakan
+90 312 445 04 64 Extension: 306
[email protected]
Appendix 2: Affirmation regarding public funding
The project does not obtain any public funding.
Appendix 3: Applicability of selected methodology
Not available.
UNFCCC/CCNUCC
Page 71
Appendix 4: Further background information on ex ante calculation of emission reductions
Power Plants Used to Calculate the Build Margin Emission Reduction Sorted by Commissioning Date
from the Newest to the Oldest (The System at the End of 2011 with CDM-VER Projects and Capacity
Additions from Retrofits of Power Plants Removed)
No
Fuel /
Energy POWER PLANT NAME
Source
Installed
Capacity
(MW)
Firm
Generation
Capacity (year
2012) (GWh)
Commissioning
Date
Location
(Province)
1
NG
TİRENDA TİRE
58.400
410.0
2011-12-30 Izmir
2
NG
AKSA AKRİLİK KİMYA (İTH.KÖM.+D.G)
25.000
175.0
3
NG
8.730
65.7
2011-12-30 Yalova
2011-12-29 Izmir
4
IC
BEKİRLİ TES (İÇDAŞ ELEKT.)
600.000
4,320.0
5
HE
SARIKAVAK (ESER)
8.100
24.0
6
FO
MARDİN-KIZILTEPE(AKSA EN.)
32.100
225.0
7
HE
ÇUKURÇAYI HES (AYDEMİR)
1.800
4.0
8
NG
ODAŞ DOĞAL GAZ
55.000
415.0
MURATLI HES (ARMAHES ELEK.)
26.700
55.0
21.0
9
HE
10
NG
TEKİRDAĞ TEKS.(NİL ÖRME)
2.700
11
NG
SARAY HALI A.Ş.
4.300
33.0
12
HE
TEFEN HES (AKSU)
11.000
26.7
13
HE
YEDİGÖL REG. VE HES (YEDİGÖL HES)
21.900
42.0
14
NG
AKSA ENERJİ (Antalya)
190.000
1,321.7
15
NG
GOREN-1 (GAZİANTEP ORG.SAN.)
48.700
277.0
16
HE
ÇANAKÇI HES (CAN EN.)
4.633
11.0
17
NG
110.000
765.2
18
HE
BOĞUNTU (BEYOBASI EN.ÜR.)
3.800
10.0
19
HE
POYRAZ HES(YEŞİL EN.)
20
NG
BOSEN (Bursa San.)
21
HE
22
23
24
2.700
6.0
93.000
698.0
ÇANAKÇI HES (CAN EN.)
4.633
11.0
WS
CEV EN.(GAZİANTEP ÇÖP)
4.524
29.6
HE
ÇAMLIKAYA
2.824
3.7
NG
GORDİON AVM (REDEVCO ÜÇ )
2.000
15.0
25
HE
BALKONDU I HES (BTA ELEK.)
9.200
20.0
26
HE
KORUKÖY HES (AKAR EN.)
3.000
13.0
27
NG
LOKMAN HEKİM ENGÜRÜ(SİNCAN)
28
NG
ŞANLIURFA OSB (RASA EN.)
29
NG
HASIRCI TEKSTİL TİC. VE SAN.
30
NG
KNAUF İNŞ. VE YAPI ELEMANLARI
31
NG
MANİSA O.S.B.
32
HE
TUZTAŞI HES (GÜRÜZ ELEK. ÜR. LTD.ŞTİ.)
33
NG
34
HE
35
HE
36
2011-11-25
2011-11-18
2011-11-03
2011-10-28
2011-10-27
2011-10-25
2011-10-15
2011-10-13
2011-10-13
2011-10-07
2011-09-30
2011-09-29
Mersin
Mardin
Isparta
Sanliurfa
Sivas
Tekirdag
Kayseri
Zonguldak
Erzurum
Antalya
Gaziantep
Trabzon
2011-09-17 Antalya
2011-09-16 Mersin
2011-09-16 K.Maras
2011-09-10
2011-08-25
2011-08-24
2011-08-11
2011-08-05
Bursa
Trabzon
Trabzon
Gaziantep
Trabzon
Ankara
1.600
12.0
43.500
347.8
1.600
6.0
130.950
986.0
KÖYOBASI HES (ŞİRİKOĞLU ELEK.)
YAŞIL HES (YAŞIL ENERJİ EL. ÜRETİM
A.Ş.)
1.100
3.0
2011-08-05
2011-08-05
2011-07-29
2011-07-26
2011-07-16
2011-07-15
2011-07-13
2011-07-04
2011-07-01
2011-06-30
2.276
4.8
2011-06-29 K.Maras
NG
POLYPLEX EUROPA
3.904
30.7
37
HE
ÜZÜMLÜ HES (AKGÜN EN. ÜR. VE TİC. A.Ş.)
11.400
23.0
38
NG
ALDAŞ ALTYAPI YÖN.
2.000
15.0
39
HE
GÖKMEN REG. (SU-GÜCÜ ELEK.)
2.900
8.0
0.500
4.0
116.800
800.0
2.000
15.0
2011-06-24
2011-06-23
2011-06-15
2011-06-15
Adiyaman
Ankara
Sanliurfa
Gaziantep
Ankara
Manisa
Sivas
Izmir
K.Maras
Tekirdag
Erzincan
Antalya
Yozgat
UNFCCC/CCNUCC
Page 72
40
HE
41
HE
KARASU II HES (İDEAL EN.)
42
HE
ÖREN REG.(ÇELİKLER)
43
HE
44
HE
45
NG
46
HE
47
HE
48
HE
KESME REG.(KIVANÇ EN.)
49
HE
ALKUMRU BARAJI VE HES(LİMAK)
50
NG
GLOBAL ENERJİ (PELİTLİK)
51
HE
KAZANKAYA REG.İNCESU HES(AKSA)
52
HE
YAPRAK II HES (NİSAN EL. ENERJİ)
53
NG
CENGİZ ENERJİ (Tekkeköy/SAMSUN)
54
NG
BOYTEKS TEKS.
55
HE
56
HE
57
HE
ALKUMRU BARAJI VE HES(LİMAK)
58
NG
59
HE
KULP I HES (YILDIZLAR EN.)
60
HE
61
HE
62
NG
TÜPRAŞ (Orta Anadolu-Kırıkkale)
12.000
84.8
63
HE
HACININOĞLU HES (ENERJİ-SA)
71.140
102.0
64
NG
İSTANBUL SABİHA GÖKÇEN HAV.
4.000
32.0
65
NG
HG ENERJİ
66
HE
YEDİGÖZE HES
67
NG
FRAPORT İÇ İÇTAŞ ANTALYA HAV.
68
HE
BAYRAMHACILI (SENERJİ EN.)
69
HE
70
HE
71
NG
INTERNATIONAL HOSPITAL (İstanbul)
72
NG
RASA ENERJİ (VAN)
73
IC
EREN ENERJİ ELEK.ÜR.A.Ş.
74
NG
ALARKO ALTEK
75
NG
POLYPLEX EUROPA
76
FO
77
HE
78
NG
SÖNMEZ ELEKTRİK
79
HE
80
BG
81
NG
82
NG
83
TEFEN HES (AKSU)
22.000
53.3
3.100
8.0
6.600
16.0
25.200
71.0
1.518
3.2
ZORLU ENERJİ (B.Karıştıran)
7.200
54.1
KESME REG.(KIVANÇ EN.)
2.305
4.5
YAPRAK II HES (NİSAN EL. ENERJİ)
5.400
10.5
İNCİRLİ REG.(LASKAR EN.)
YAŞIL HES (YAŞIL ENERJİ EL. ÜRETİM
A.Ş.)
2.305
4.5
87.090
156.0
4.000
29.9
15.000
27.0
5.400
10.5
35.000
281.3
8.600
67.0
HACININOĞLU HES (ENERJİ-SA)
71.140
102.0
NARİNKALE HES (EBD EN.)
30.400
55.4
174.180
312.0
3.904
18.0
22.900
44.0
DURU 2 REG.(DURUCASU EL.)
4.500
13.0
ÇAKIRMAN (YUSAKA EN.)
7.000
15.0
GÜLLE ENTEGRE (Çorlu)
52.400
366.0
155.330
134.0
8.000
64.0
47.000
95.0
AKSU REG.(KALEN EN.)
5.200
12.0
ÇEŞMEBAŞI (GİMAK)
8.200
17.0
0.800
6.0
10.124
64.4
600.000
4,005.9
21.890
151.4
7.808
61.3
TÜPRAŞ (İzmit-Yarımca)
40.000
258.8
UMUT III HES(NİSAN EL.)
12.000
15.0
2.564
19.8
YEDİGÖZE HES
155.330
134.0
FRİTOLEY GIDA
0.330
2.5
69.840
525.9
MARMARA PAMUK
26.190
203.6
HE
MURGUL BAKIR
19.602
31.5
84
HE
KARADENİZ ELEK.(UZUNDERE I HES)
85
IC
86
HE
SABUNSUYU II HES (ANG EN.)
87
HE
KAHTA I HES(ERDEMYILDIZ ELEK.)
88
NG
ENERJİ-SA (Bandırma)
31.076
46.5
600.000
4,005.9
7.400
12.0
7.100
20.0
930.800
7,540.0
2011-06-10
2011-06-03
2011-05-26
2011-05-25
Zonguldak
Erzurum
Giresun
Rize
2011-05-20 K.Maras
2011-05-14
2011-04-22
2011-04-22
2011-04-14
2011-04-12
2011-04-08
2011-04-08
2011-04-03
2011-03-30
2011-03-19
2011-03-17
2011-03-17
2011-03-10
2011-03-04
2011-03-04
2011-02-25
2011-02-19
2011-02-04
2011-02-03
2011-01-31
2011-01-27
2011-01-26
2011-01-24
2011-01-20
2011-01-12
2011-01-12
2010-12-31
2010-12-29
2010-12-29
2010-12-18
2010-12-16
2010-12-15
2010-12-13
Kirklareli
2010-12-07
2010-12-02
2010-11-26
2010-11-26
2010-11-25
2010-11-11
2010-11-07
2010-11-01
2010-10-28
2010-10-14
2010-10-07
Usak
K.Maras
Amasya
K.Maras
Siirt
Tekirdag
Çorum
Amasya
Samsun
Kayseri
K.Maras
Kars
Siirt
Tekirdag
Diyarbakir
Amasya
Erzincan
Kirikkale
K.Maras
Istanbul
Kutahya
Adana
Antalya
Nevsehir
Giresun
Ankara
Istanbul
Van
Zonguldak
Kirklareli
Tekirdag
Kocaeli
Ordu
Adana
Kocaeli
Izmir
Tekirdag
Artvin
Rize
Zonguldak
Osmaniye
Adiyaman
Balikesir
UNFCCC/CCNUCC
Page 73
89
NG
UĞUR ENERJİ (TEKİRDAĞ)
12.000
100.9
90
HE
ERENKÖY REG.(TÜRKERLER)
21.500
49.0
91
HE
KAHRAMAN REG.(KATIRCIOĞLU ELEK.)
1.400
3.0
92
HE
NARİNKALE HES (EBD EN.)
3.100
5.6
93
FO
KIRKA BORAKS (Kırka)
10.000
65.9
94
HE
KOZAN HES (SER-ER EN.)
4.000
5.0
95
HE
TEKTUĞ-ANDIRIN
40.500
60.0
96
HE
KARŞIYAKA HES (AKUA EN.)
97
NG
SÖNMEZ ELEKTRİK
98
HE
GÜDÜL I (YAŞAM EN.)
99
NG
KURTOĞLU BAKIR KURŞUN
100 NG
CAN ENERJİ ELEK. ÜR.AŞ.(TEKİRDAĞ)
101 NG
BİNATOM ELEKTRİK ÜRT. A.Ş.
102 NG
KESKİNOĞLU TAVUKÇULUK
103 HE
GÖK HES
104 NG
105 NG
1.600
5.0
33.242
256.2
2.400
8.0
1.600
12.0
29.100
203.0
2.000
13.0
3.500
25.0
10.000
24.0
101.950
819.4
RB KARESİ TEKS. (BURSA)
8.600
65.0
106 NG
FLOKSER TEKSTİL (ÇERKEZKÖY)
5.200
42.0
107 IC
160.000
1,068.2
22.500
47.0
6.200
13.0
108 HE
YAVUZ HES (MASAT EN.)
109 HE
KİRPİLİK HES (ÖZGÜR ELEK.)
110 NG
ALARKO ALTEK
60.100
415.6
111 HE
DİM HES (DİLER ELEK.)
38.300
70.0
112 HE
DİNAR HES (ELDA ELEK.)
113 NG
114 HE
ÇAMLIKAYA
115 NG
4.400
9.0
25.000
173.9
5.648
7.3
UĞUR ENERJİ (TEKİRDAĞ)
48.200
405.1
116 HE
ERENLER REG.(BME BİRLEŞİK EN.)
45.000
48.0
117 HE
KARADENİZ ELEK.(UZUNDERE I HES)
31.076
46.5
118 NG
101.950
819.4
78.400
473.3
119 NG
ERDEMİR
120 HE
BİRİM (ERFELEK HES)
3.225
5.5
277.9
92.7
121 NT
ATAER ENERJİ (EBSO)
49.000
122 NG
YILDIZ ENTEGRE
12.368
123 BG
FRİTOLEY GIDA
0.065
0.5
21.600
39.0
NİSAN EN.(BAŞAK HES)
6.900
12.0
BİRİM (ERFELEK HES)
3.225
5.5
127 HE
NURYOL EN.(DEFNE HES)
7.200
13.0
128 NG
25.000
173.9
129 HE
DOĞUBAY ELEK.(SARIMEHMET HES)
3.100
6.0
26.190
166.6
124 HE
FIRTINA ELEK.(SÜMER HES)
125 HE
126 HE
130 NG
RASA ENERJİ (VAN)
131 WS
ORTADOĞU ENERJİ (Oda yeri)
4.245
33.2
132 HE
HETAŞ HACISALİHOĞLU (YILDIZLI HES)
1.200
3.0
133 HE
PETA EN. (MURSAL II HES)
4.500
11.0
134 NG
AKBAŞLAR
1.540
11.69
135 WS
CEV EN.(GAZİANTEP ÇÖP)
1.131
7.4
136 HE
ALAKIR (YURT EN.)
2.100
4.0
ALTINMARKA
4.600
35.9
CAN TEKSTİL (Çorlu)
7.832
60.1
137 NG
138 NG
2010-10-07
2010-10-07
2010-09-30
2010-09-30
2010-09-29
2010-09-21
2010-09-03
2010-08-28
2010-08-26
2010-08-25
2010-08-19
2010-08-19
2010-08-17
2010-08-11
2010-08-06
2010-07-31
2010-07-23
2010-07-17
2010-07-15
Tekirdag
2010-07-14
2010-07-11
2010-07-10
2010-07-08
Amasya
Artvin
Giresun
Kars
Eskisehir
Adana
K.Maras
Gaziantep
Usak
Malatya
Tekirdag
Tekirdag
Kutahya
Manisa
Mersin
Samsun
Bursa
Tekirdag
Zonguldak
Mersin
Kirklareli
Antalya
2010-07-03 Tunceli
2010-07-01
2010-06-30
2010-06-21
2010-06-04
Antalya
2010-05-27
2010-05-22
2010-05-21
2010-05-14
2010-05-05
2010-04-22
2010-04-21
2010-04-16
2010-04-09
2010-04-03
2010-03-26
2010-03-20
2010-03-11
2010-03-03
Rize
Trabzon
Tekirdag
Artvin
Samsun
Zonguldak
Sinop
Izmir
Kocaeli
Kocaeli
Giresun
Kastamonu
Sinop
Duzce
Antalya
Van
Van
2010-02-24 Istanbul
2010-02-23 Trabzon
2010-02-19
2010-02-18
2010-02-01
2010-01-29
2010-01-28
2010-01-28
Sivas
Bursa
Gaziantep
Antalya
Istanbul
Tekirdag
UNFCCC/CCNUCC
139 HE
Page 74
BAYBURT HES
14.600
24.0
140 HE
UZUNÇAYIR
54.660
121.3
141 LN
ETİ SODA
24.000
144.0
9.573
16.7
142 HE
CİNDERE DENİZLİ
143 HE
KULP IV HES (YILDIZLAR EN.)
12.300
23.0
144 NG
TÜPRAŞ (Orta Anadolu-Kırıkkale)
34.000
240.2
2.450
4.5
145 HE
SARITEPE HES DİNAMİK SİSTEMLER
146 NG
AKSA ENERJİ (Manisa)
10.500
83.2
147 NG
FALEZ ELEKTRİK
11.700
88.0
2.000
16.0
148 NG
ÇELİKLER RİXOS ANKARA OTEL
149 NG
TAV İSTANBUL
150 HE
UZUNÇAYIR
3.260
27.3
27.330
60.7
4.5
151 HE
SARITEPE HES DİNAMİK SİSTEMLER
2.450
152 HE
ÖZYAKUT GÜNEŞLİ HES
0.600
1.3
SELKASAN
9.900
73.0
30.100
65.0
153 NG
154 HE
TÜM EN. PINAR
155 HE
ERVA KABACA HES
4.240
7.5
126.100
1,008.0
AKGIDA PAMUKOVA
7.500
61.0
2.7
54.1
156 NG
CAM İŞ ELEKTRİK (Mersin)
157 NG
158 NG
MAURİ MAYA
0.330
159 FO
KIRKA BORAKS (Kırka)
8.200
160 NG
DALSAN ALÇI
1.200
9.0
161 IC
İÇDAŞ ÇELİK
135.000
961.7
162 HE
ERVA KABACA HES
163 NG
4.240
7.5
101.2
364.0
DELTA ENERJİ
13.000
164 FO
ALİAĞA PETKİM
52.000
165 HE
DENİZLİ EGE 1
0.900
2.0
166 WS
5.660
44.3
167 HE
AKÇAY
28.800
45.0
168 NG
ENTEK (Köseköy) İztek
12.400
98.7
8.553
64.0
169 NG
170 NG
RASA ENERJİ (VAN)
78.570
499.9
171 HE
OBRUK I-II
210.800
614.0
172 IC
İÇDAŞ ÇELİK
135.000
961.7
173 HE
KAYEN ALFA EN.KALETEPE HES (tortum)
10.200
17.0
49.530
371.9
5.800
20.0
300.000
2,087.0
4.400
7.0
33.3
174 NG
175 HE
AKUA KAYALIK
176 NG
177 HE
ŞİRİKÇİOĞLU KOZAK
178 HE
CİNDERE DENİZLİ
19.146
179 NG
MARMARA PAMUK
34.920
271.5
180 NG
ANTALYA ENERJİ
41.820
302.2
181 NG
300.000
2,087.0
2.7
182 HE
ÖZYAKUT GÜNEŞLİ HES
1.200
183 NG
MAURİ MAYA
2.000
16.3
184 BG
CARGİLL TARIM
0.100
0.7
TOCAK I HES (YURT ENERJİ ÜRETİM SAN.)
4.800
6.0
135.000
945.0
46.950
352.2
2.300
18.0
185 HE
186 AS
SİLOPİ ASFALTİT
187 NG
NUH ENERJİ (ENER SANT.2)
188 NG
TESKO KİPA İZMİR
2010-01-28
2010-01-28
2010-01-22
2010-01-21
2010-01-13
2009-12-25
2009-12-24
2009-12-18
2009-12-16
2009-12-15
2009-12-12
2009-12-02
2009-11-19
2009-11-13
2009-11-11
2009-11-06
2009-10-29
Bayburt
2009-10-19
2009-10-17
2009-10-16
2009-10-15
2009-10-14
Mersin
Tunceli
Ankara
Denizli
Diyarbakir
Kirikkale
Adana
Manisa
Antalya
Ankara
Istanbul
Tunceli
Adana
K.Maras
Manisa
Adiyaman
Artvin
Sakarya
Balikesir
Eskisehir
Kocaeli
2009-09-23 Artvin
2009-09-17
2009-08-28
2009-08-27
2009-08-14
2009-08-14
2009-08-06
2009-07-31
2009-07-31
2009-07-29
2009-07-24
2009-07-23
2009-07-17
2009-07-15
2009-07-10
2009-07-08
2009-07-02
2009-06-18
2009-06-05
2009-05-29
2009-05-29
Kirklareli
2009-05-28
2009-05-26
2009-05-08
2009-05-02
2009-04-30
2009-04-27
Balikesir
Izmir
Denizli
Istanbul
Aydın
Kocaeli
Tekirdag
Van
Corum
Canakkale
Erzurum
Kirklareli
Erzincan
Antalya
K.Maras
Denizli
Tekirdag
Antalya
Antalya
K.Maras
Bursa
Antalya
Sirnak
Kocaeli
Izmir
UNFCCC/CCNUCC
189 NG
Page 75
KEN KİPAŞ (KAREN)ELEKTRİK
17.460
75.2
190 NG
DELTA ENERJİ
47.000
365.8
191 NG
K.Maras
201 NG
52.380
202 NG
46.700
324.9
2.830
22.1
KARKEY (SİLOPİ)
SARMAŞIK I HES (FETAŞ FETHİYE
ENERJİ)
SARMAŞIK II HES (FETAŞ FETHİYE
ENERJİ)
14.780
95.8
2009-04-23
2009-04-21
2009-04-17
2009-04-02
2009-03-27
2009-03-26
2009-03-06
2009-03-04
2009-02-26
2009-02-06
2009-01-30
2009-01-30
2009-01-15
2008-12-29
2008-12-29
2008-12-19
21.000
54.0
2008-11-28 Trabzon
21.600
61.0
2008-11-28 Trabzon
AKKÖY ENERJİ (AKKÖY HES)
33.980
87.7
2008-11-26
2008-11-07
2008-10-17
2008-10-16
2008-10-10
2008-10-10
2008-09-25
2008-09-18
2008-09-17
2008-09-16
2008-09-04
2008-08-29
2008-08-08
2008-08-01
2008-07-31
2008-07-25
2008-07-19
2008-07-04
2008-07-03
2008-07-03
2008-05-22
2008-05-17
Gumushane
324.9
2008-04-02
2008-03-07
2008-02-23
2008-02-22
2008-02-21
2008-01-30
2008-01-29
2008-01-24
2008-01-04
Tekirdag
16.200
112.7
192 GT
GÜRMAT EN.
47.400
313.0
193 NG
SÖNMEZ ELEKTRİK
8.730
67.3
194 NG
KASAR DUAL TEKS.ÇORLU
5.700
38.0
195 NG
TAV İSTANBUL
6.520
54.7
196 WS
4.245
33.2
197 LN
ALKİM (ALKALİ KİMYA) (Konya)
0.400
3.0
236.7
198 NG
ERDEMİR
39.200
199 NG
TÜPRAŞ ALİAĞA
24.700
170.0
2.000
6.0
414.9
200 HE
203 WS
204 FO
205 HE
206 HE
207 HE
208 NG
TAŞOVA YENİDEREKÖY
46.700
209 NG
46.700
324.9
210 HE
TORUL
103.200
264.0
17.460
138.3
0.800
4.0
211 NG
212 HE
YEŞİL ENERJİ (TAYFUN HES)
213 HE
DAREN HES (SEYRANTEPE BARAJI)
24.850
80.5
214 HE
AKKÖY ENERJİ (AKKÖY HES)
67.960
175.3
215 HE
DAREN HES (SEYRANTEPE BARAJI)
24.850
80.5
216 NG
34.920
276.6
217 NG
43.700
304.0
218 HE
H.G.M.ENER.(KEKLİCEK HES)
219 NG
ANTALYA ENERJİ
220 NG
POLAT RÖNESANS
221 HE
HİDRO KONTROL YUKARI MANAHOZ
222 NG
8.700
11.0
17.460
126.2
1.600
11.0
22.400
45.0
67.3
SÖNMEZ ELEKTRİK
8.730
223 HE
CANSU ELEKTRİK (ARTVİN)
9.200
31.0
224 NG
MODERN ENERJİ
9.520
66.9
225 NG
BAHÇIVAN GIDA (LÜLEBURGAZ)
1.200
8.0
226 NG
MELİKE TEKSTİL G.ANTEP
1.600
11.0
227 HE
İÇ-EN ELEK. ÇALKIŞLA
7.700
11.0
228 NG
FOUR SEASONS OTEL
1.200
7.0
229 NG
CAN ENERJİ
34.920
202.9
CAN ENERJİ
17.460
101.4
0.060
0.4
22.600
146.3
14.0
230 NG
231 NG
FRİTOLEY GIDA
232 NG
YILDIZ SUNTA (Köseköy)
233 NG
MİSİS APRE TEKSTİL ADANA
2.000
234 NG
ATAÇ İNŞSAN. ANTALYA
5.400
37.0
235 HE
TEMSA ELEKTRİK (GÖZEDE HES)
2.400
6.0
236 HE
ALP ELEKTRİK (TINAZTEPE)
7.700
17.0
237 NG
KESKİN KILIÇ SULTANHANI
8.800
60.0
Kirklareli
Antalya
Aydin
Usak
Tekirdag
Istanbul
Istanbul
Konya
Zonguldak
Izmir
Amasya
Manisa
Antalya
Istanbul
Sirnak
Antalya
Antalya
Gumushane
Manisa
K.Maras
Elazig
Gumushane
Elazig
Manisa
Antalya
Malatya
Antalya
Istanbul
Trabzon
Usak
Artvin
Tekirdag
Kirklareli
Gaziantep
Erzincan
Istanbul
Tekirdag
Kocaeli
Kocaeli
Adana
Antalya
Bursa
Antalya
Aksaray
UNFCCC/CCNUCC
238 GT
Page 76
SARAYKÖY JEOTERMAL
6.900
50.0
239 HE
MERCAN ZORLU
1.275
3.0
240 FO
KARKEY (SİLOPİ)
29.560
191.6
241 NG
SÜPERBOY BOYA
1.000
8.0
242 NG
FLOKSER TEKSTİL (Poliser)
2.100
17.0
243 HE
KURTEKS (Karasu Andırın HES)
2.400
19.0
244 NG
ACIBADEM Kadıköy 2
0.600
5.0
245 NG
TAV Esenboğa
3.900
33.0
246 NG
34.840
262.3
247 NG
BİS ENERJİ (Bursa San.)
28.300
233.5
248 NG
48.000
396.1
11.0
249 NG
ACIBADEM Bursa
1.300
250 NG
SWISS OTEL (İstanbul)
1.600
11.0
251 NG
AKATEKS Çorlu
1.800
14.0
47.0
4.0
252 NG
SAYENERJİ (Kayseri OSB)
5.900
253 NG
ACIBADEM Kadıköy 1
0.500
254 NG
ENTEK (Demirtaş)
10.750
81.1
255 NG
43.000
354.8
256 HE
ÖZGÜR ELEKTR.K.Maraş Tahta HES
6.250
27.0
257 HE
ÖZGÜR ELEKTR.K.Maraş Tahta HES
6.250
27.0
23.000
184.0
258 NG
HABAŞ (Aliağa)
259 NG
T. ENERJİ TURCAS
1.600
13.0
260 FO
ORS (Polatlı)
7.400
51.5
261 NG
KIVANÇ TEKSTİL
3.900
33.0
262 HE
BORÇKA
300.600
927.2
25.0
263 NG
KİL-SAN
3.200
264 NG
FRİTOLEY GIDA
0.540
3.6
265 NG
BOSEN (Bursa San.)
11.800
88.6
266 NG
AKMAYA (Lüleburgaz)
6.900
48.0
267 NG
BURGAZ ELEKTRİK
6.900
55.0
268 WD
ERTÜRK ELEKT. (TEPE)
0.900
2.0
13.300
46.7
269 HE
BEREKET (MENTAŞ)
270 NG
ÇIRAĞAN SARAYI
271 HE
ENERJİ-SA-AKSU-ŞAHMALLAR
1.300
11.0
14.000
7.0
360.000
1,306.5
272 LN
ELBİSTAN B 1-4
273 NG
37.000
294.6
ÇERKEZKÖY ENERJİ
49.200
403.0
46.3
274 NG
275 NG
YILDIZ ENTEGRE
6.184
276 LN
ELBİSTAN B 1-4
360.000
1,306.5
CAM İŞ ELEKTRİK (Mersin)
126.100
1,008.0
8.0
277 NG
278 HE
ENERJİ SA-SUGÖZÜ-KIZILDÜZ
15.400
279 HE
EKİN ENERJİ (BAŞARAN HES)
0.600
0.0
280 NG
EROĞLU GİYİM
1.200
9.0
281 WS
EKOLOJİK ENERJİ (Kemerburgaz)
1.000
8.0
282 HE
BEREKET (MENTAŞ)
26.600
93.3
283 NG
HAYAT TEMİZLİK
15.000
94.0
284 NG
ANTALYA ENERJİ
34.920
252.4
4.600
4.0
360.000
1,306.5
1.600
13.0
285 HE
SU ENERJİ (ÇAYGÖREN HES)
286 LN
ELBİSTAN B 1-4
287 NG
ŞIK MAKAS
2008-01-04
2008-01-01
2007-12-13
2007-12-06
2007-12-04
2007-11-29
2007-10-24
2007-09-20
2007-09-14
2007-09-11
2007-08-31
2007-08-29
2007-08-02
2007-07-31
2007-07-12
2007-06-20
2007-06-15
2007-05-31
2007-05-25
2007-05-04
2007-05-03
2007-04-05
2007-03-23
2007-03-21
2007-02-28
2007-02-20
2007-01-24
2007-01-19
2006-12-23
2006-12-23
2006-12-22
2006-12-13
2006-12-01
2006-11-16
2006-11-13
2006-11-03
2006-10-06
2006-09-21
2006-09-17
2006-09-13
2006-09-08
2006-08-11
2006-08-01
2006-07-31
2006-07-31
2006-06-30
Denizli
2006-06-29
2006-06-27
2006-06-23
2006-06-22
Antalya
Tunceli
Sirnak
Istanbul
Istanbul
K.Maras
Istanbul
Ankara
Izmir
Bursa
Bursa
Bursa
Istanbul
Tekirdag
Kayseri
Istanbul
Bursa
Bursa
K.Maras
K.Maras
Izmir
Istanbul
Ankara
Adana
Artvin
Istanbul
Kocaeli
Bursa
Kirklareli
Kirklareli
Istanbul
Adana
Istanbul
Antalya
K.Maras
Kocaeli
Tekirdag
Kocaeli
K.Maras
Mersin
Antalya
Aydin
Tekirdag
Istanbul
Adana
Kocaeli
Balikesir
K.Maras
Tekirdag
UNFCCC/CCNUCC
288 NG
Page 77
AMYLUM NİŞASTA (Adana)
8.100
45.31
289 BG
ADANA ATIK
0.800
6.0
290 HE
MOLU ENERJİ (BAHÇELİK HES)
4.200
30.0
291 NG
KASTAMONU ENTEGRE
7.500
48.0
292 HE
BEREKET (GÖKYAR)
11.600
23.0
293 NG
SÖNMEZ ELEKTRİK
17.460
134.6
3.200
25.0
47.620
379.2
8.730
67.9
195.6
294 NG
ELSE TEKSTİL
295 NG
296 NG
MARMARA PAMUK
297 NG
26.080
298 HE
ŞANLI URFA
51.000
145.0
AYDIN ÖRME
7.500
60.0
21.890
151.4
299 NG
300 NG
ALARKO ALTEK
301 NG
ERAK GİYİM
1.400
12.0
EKOTEN TEKSTİL
1.900
15.0
51.020
382.9
302 NG
303 NG
BOSEN (Bursa San.)
304 FO
KARKEY (SİLOPİ)
6.750
43.8
305 NT
MENDERES TEKS. (AKÇA ENERJİ)
8.730
63.9
306 IC
KAHRAMANMARAŞ KAĞIT
6.000
45.0
43.0
307 NG
PAKGIDA (Kemalpaşa)
5.700
308 NG
KORUMA KLOR
9.600
77.0
309 IC
İÇDAŞ ÇELİK
135.000
961.7
64.0
2006-06-09
2006-06-09
2006-05-31
2006-05-24
2006-05-05
2006-05-03
2006-04-15
2006-04-14
2006-04-13
2006-03-02
2006-03-01
2006-02-25
2006-02-23
2006-02-22
2006-02-16
2005-12-30
2005-12-23
2005-12-14
2005-12-08
2005-12-07
Adana
Kocaeli
Adana
Kayseri
Balikesir
Mugla
Usak
Tekirdag
Kocaeli
Tekirdag
Kocaeli
Sanliurfa
Sakarya
Kirklareli
Tekirdag
Izmir
Bursa
Sirnak
Denizli
K.Maras
Izmir
MANİSA O.S.B.
84.834
678.2
315 NG
AK ENERJİ (Kemalpaşa)
40.000
328.3
2005-12-03
2005-11-30
2005-11-27
2005-11-26
2005-11-24
2005-11-14
2005-11-11
2005-11-09
316 NG
ZORLU ENERJİ (Kayseri)
38.630
294.9
2005-10-26 Kayseri
317 NG
ALARKO ALTEK
60.100
415.6
2005-10-14 Kirklareli
318 NG
AYKA TEKSTİL
5.500
41.0
319 NG
HABAŞ (Aliağa)
44.615
357.0
5.100
30.0
164.8
310 NG
KÜÇÜKÇALIK TEKSTİL
8.000
311 NG
ZORLU ENERJİ (Yalova)
15.900
122.3
312 NG
HABAŞ (Aliağa)
23.000
184.0
5.500
42.0
313 NG
GRANİSER GRANİT
314 NG
320 NG
EVYAP
321 NG
ÇEBİ ENERJİ
21.000
322 NG
CAN ENERJİ
3.900
22.7
323 NG
NOREN ENERJİ
8.700
70.0
324 NG
ÇEBİ ENERJİ
43.366
340.2
325 HE
YAMULA
100.000
422.0
326 NG
ZORLU ENERJİ (Kayseri)
149.871
1,144.1
327 BG
BANDIRMA ASİT(ETİ MADEN)
11.500
88.0
328 HE
BEREKET (DALAMAN)
7.500
35.8
329 NG
ZEYNEP GİYİM
1.200
9.0
330 FO
KARKEY (SİLOPİ)
6.150
39.9
AKBAŞLAR
5.040
38.25
10.240
72.0
115.000
460.5
44.615
357.0
28.0
331 NG
332 NG
MODERN ENERJİ
333 HE
MURATLI
334 NG
HABAŞ (Aliağa)
335 NG
TEZCAN GALVANİZ GR I-II
3.500
336 NG
HAYAT KAĞIT SAN.
7.200
56.3
YONGAPAN (Kastamonu)
5.200
30.5
337 NG
2005-09-24
2005-09-21
2005-08-27
2005-08-27
2005-08-25
2005-08-24
2005-08-23
2005-07-30
2005-07-22
2005-07-15
2005-07-15
2005-07-07
2005-06-30
2005-06-24
2005-06-13
2005-06-02
2005-06-02
2005-05-27
2005-05-27
2005-05-25
Canakkale
Bursa
Yalova
Izmir
Manisa
Manisa
Izmir
Tekirdag
Izmir
Istanbul
Tekirdag
Tekirdag
Nigde
Tekirdag
Kayseri
Kayseri
Balikesir
Mugla
Tekirdag
Sirnak
Bursa
Tekirdag
Artvin
Izmir
Kocaeli
Corum
Kocaeli
UNFCCC/CCNUCC
338 NG
Page 78
46.950
352.2
339 HE
İÇTAŞ YUKARI MERCAN
14.200
20.0
340 NG
AK ENERJİ (Kemalpaşa)
87.200
715.7
1.200
2.0
341 WD
SUNJÜT
342 NG
KAREGE ARGES
17.460
138.9
343 NG
43.700
360.6
976.5
344 LN
ÇAN 1-2
160.000
345 LN
ÇAN 1-2
160.000
976.5
346 LN
ELBİSTAN B 1-4
360.000
1,306.5
19.0
347 NG
ENTEK (KOÇ Üniversite)
2.300
348 NG
BAYDEMİRLER (Beylikdüzü)
6.210
51.5
MERCEDES BENZ
8.300
68.0
11.748
87.8
349 NG
350 NG
351 NG
GLOBAL ENERJİ (HACIŞİRAHMET)
7.800
58.0
10.5
7.0
352 FO
TÜPRAŞ (Batman)
1.500
353 NG
BAHARİYE MENSUCAT
1.000
354 NG
ALTINMARKA
355 FO
KARKEY (SİLOPİ)
356 NG
STANDARD PROFİL
357 NG
HABAŞ (Aliağa)
3.596
28.1
54.300
351.9
6.700
49.0
89.230
714.0
84.0
358 NG
AYEN OSTİM
9.890
359 NG
KOMBASSAN AMBALAJ (Konya)
5.500
40.0
360 HE
BEREKET (FESLEK)
9.500
25.0
361 NG
ÇELİK ENERJİ (Uzunçiftlik)
2.400
19.0
362 NG
BERK ENERJİ (BESLER -KURTKÖY)
4.400
30.9
ŞAHİNLER ENERJİ(ÇORLU/TEKİRDAĞ)
3.200
22.8
325.0
363 NG
364 NG
ENERJİ-SA (Adana)
49.770
365 NG
73.000
602.3
366 NG
AYEN OSTİM
31.077
264.0
367 NG
KOMBASSAN AMBALAJ (Tekirdağ)
5.500
38.0
368 NG
TEKBOY TEKSTİL
2.200
16.0
45.000
337.5
369 IC
ÇOLAKOĞLU-2
370 HE
İŞKUR (SÜLEYMANLI HES)
4.600
4.0
371 HE
ELTA (DODURGA)
4.100
12.0
10.400
82.0
372 LPG
ETİ BOR (EMET)
373 NG
TANRIVERDİ
374 HE
ENERJİ-SA BİRKAPILI
375 NG
ATATEKS TEKSTİL
376 NG
ENTEK (Demirtaş)
377 NG
ANKARA
378 NG
ECZACIBAŞI BAXTER
379 NG
SÖNMEZ FLAMENT
380 IC
İSKENDERUN
381 NG
ENERJİ-SA (Mersin)
382 HE
BATMAN
4.700
39.0
48.500
17.0
5.600
45.0
31.132
234.7
798.000
5,209.0
1.000
6.0
4.100
29.0
1,320.000
7,706.0
21.575
177.4
198.500
450.0
175.0
383 NG
ENERJİ-SA (Çanakkale)
21.575
384 NG
BATIÇİM ENERJİ (AK ENERJİ)
14.500
119.3
385 HE
PAMUK (Toroslar)
23.300
28.0
386 HE
MERCAN ZORLU
19.100
45.0
387 NG
ENERJİ-SA (Mersin)
41.650
342.6
2005-05-24
2005-05-21
2005-04-30
2005-04-22
2005-04-07
2005-03-18
2005-03-15
2005-02-15
2005-02-15
2005-02-07
2005-02-04
2005-02-04
2005-01-29
2005-01-29
2004-12-31
2004-12-31
2004-12-17
2004-11-12
2004-10-22
2004-10-08
2004-10-01
2004-09-24
2004-08-05
2004-07-09
2004-07-07
2004-06-29
2004-06-23
2004-06-16
2004-06-11
2004-06-09
2004-05-18
2004-05-05
2004-04-28
2004-04-26
2004-04-22
2004-03-24
2004-03-11
2004-02-20
2004-02-12
2004-01-08
2003-12-31
2003-12-31
2003-11-22
2003-11-22
2003-11-14
2003-11-12
2003-10-26
2003-10-18
2003-10-08
2003-10-05
Kocaeli
Erzincan
Izmir
Istanbul
Izmir
Bursa
Canakkale
Canakkale
K.Maras
Istanbul
Istanbul
Istanbul
Tekirdag
Tekirdag
Batman
Istanbul
Istanbul
Sirnak
Duzce
Izmir
Ankara
Konya
Aydin
Kocaeli
Istanbul
Tekirdag
Adana
Bursa
Ankara
Tekirdag
Kirklareli
Kocaeli
K.Maras
Denizli
Kutahya
Tekirdag
Mersin
Tekirdag
Bursa
Ankara
Istanbul
Bursa
Hatay
Mersin
Batman
Canakkale
Izmir
Mersin
Tunceli
Mersin
UNFCCC/CCNUCC
388 HE
389 FO
390 NG
Page 79
85.000
132.9
ANADOLU EFES BİRA I
3.800
32.0
ZORLU ENERJİ (Sincan)
10.660
90.8
17.1
KÜRTÜN
391 NG
2.066
392 NG
TÜBAŞ
1.400
9.0
393 NG
PAKGIDA (Düzce-Köseköy)
2.100
16.7
394 NG
ÖZAKIM ENERJİ (Gürsu)
7.000
60.0
395 NG
KEN KİPAŞ (KAREN)ELEKTRİK
24.340
104.8
396 HE
YAPISAN HACILAR DARENDE
13.300
54.0
397 NG
ZORLU ENERJİ (Sincan)
39.700
338.2
398 NG
0.900
6.9
50.0
399 NG
YURTBAY (Eskişehir)
6.900
400 NT
ALKİM KAĞIT
3.385
26.7
401 NG
İZMİR
1,590.700
10,780.0
25.400
208.9
5.200
32.0
402 NG
403 NG
HAYAT KİMYA (İzmit)
404 FO
ALİAĞA PETKİM
21.700
151.9
405 HE
EŞEN-II (GÖLTAŞ)
21.700
40.0
406 NG
407 LN
ETİ MADEN (BANDIRMA BORAKS)
5.080
41.8
10.700
78.0
1,432.000
9,711.0
408 NG
BURSA D.GAZ
409 DO
VAN ENGİL GAZ (ZORLU ENERJİ)
15.000
75.0
410 LN
KEMERKÖY
630.000
2,698.0
411 LN
ORHANELİ
210.000
950.0
412 HC
ÇATALAĞZI-B
300.000
1,721.1
KANGAL
457.000
2,391.0
1,350.900
7,919.0
413 LN
414 NG
AMBARLI-D.GAZ
415 LN
ÇAYIRHAN PARK HOLD.
620.000
3,601.0
416 LN
YENİKÖY
420.000
2,150.0
417 NG
HAMİTABAT
1,156.000
6,804.0
418 LN
ELBİSTAN A
1,355.000
3,144.0
15.000
105.0
419 GT
ZORLU ENERJİ (DENİZLİ)
420 LN
YATAĞAN
630.000
2,869.0
421 LN
SOMA B
990.000
4,715.0
422 NG
ALİAĞA-ÇEVRİM
180.000
1,025.0
423 FO
HOPA
424 LN
50.000
241.6
3,201.0
SEYİTÖMER
600.000
425 FO
AMBARLI
630.000
0.0
426 LN
SOMA A
44.000
0.0
BİLGİN ELEK. (HAZAR 1-2)
30.100
0.0
365.000
1,499.0
427 HE
428 LN
TUNÇBİLEK
429 DO
HAKKARİ ÇUKURCA
2003-09-26
2003-09-05
2003-07-18
2003-07-11
2003-07-11
2003-07-02
2003-06-19
2003-06-14
2003-06-14
2003-05-31
2003-05-17
2003-05-16
2003-05-03
2003-03-28
2003-03-13
2003-03-11
2003-02-24
2003-01-31
2003-01-27
2003-01-10
1998-01-01
1996-01-01
1993-01-01
1992-01-01
1989-01-01
1989-01-01
1988-01-01
1987-01-01
1986-01-01
1985-01-01
1984-01-01
1984-01-01
1982-01-01
1981-01-01
1975-01-01
1973-01-01
1973-01-01
1967-01-01
1957-01-01
1957-01-01
1956-01-01
Gumushane
Ankara
Ankara
Istanbul
Tekirdag
Duzce
Bursa
K.Maras
Malatya
Ankara
Tekirdag
Eskisehir
Afyon
Izmir
Izmir
Kocaeli
Izmir
Mugla
Izmir
Balikesir
Bursa
Van
Mugla
Bursa
Zonguldak
Sivas
Istanbul
Ankara
Mugla
Kirklareli
K.Maras
Denizli
Mugla
Manisa
Izmir
Artvin
Kütahya
Istanbul
Manisa
Elazig
Kütahya
1.000
0.0
62.000
146.4
Hakkari
Denizli
27.000
93.4
Tokat
702.600
1,616.0
430 HE
ADIGÜZEL
431 HE
ALMUS
432 HE
ALTINKAYA
433 HE
ASLANTAŞ
138.000
674.9
434 HE
ATATÜRK
2,405.000
8,139.9
435 HE
BERDAN
10.200
15.0
Mersin
436 HE
ÇATALAN
168.900
646.0
Adana
437 HE
ÇAMLIGÖZE
32.000
97.5
Sivas
Samsun
Osmaniye
Sanliurfa
UNFCCC/CCNUCC
438 HE
Page 80
DEMİRKÖPRÜ
69.000
102.7
Manisa
439 HE
DERBENT
56.400
289.0
Samsun
440 HE
DİCLE
110.000
180.8
Diyarbakir
74.500
220.0
Giresun
441 HE
DOĞANKENT
442 HE
GEZENDE
159.400
220.0
Mersin
443 HE
GÖKÇEKAYA
278.400
471.1
Eskisehir
444 HE
HASAN UĞURLU
500.000
1,182.0
445 HE
HASANLAR
446 HE
HİRFANLI
Samsun
9.400
29.6
128.000
290.0
Bolu
Kirsehir
194.1
Kirikkale
447 HE
KAPULUKAYA
54.000
448 HE
KARACAÖREN-1
32.000
72.7
Burdur
KARACAÖREN II
46.400
123.0
Burdur
1,800.000
8,383.8
Diyarbakir
Gaziantep
449 HE
450 HE
KARAKAYA
451 HE
KARKAMIŞ
452 HE
189.000
672.9
7,110.0
Elazig
KEBAN
1,330.000
453 HE
KEMER
48.000
78.2
Aydin
454 HE
KESİKKÖPRÜ
76.000
173.2
Ankara
KILIÇKAYA
120.000
300.0
Sivas
456 HE
KÖKLÜCE
90.000
450.0
Tokat
457 HE
KRALKIZI
94.500
50.0
Diyarbakir
9.300
24.0
K.Maras
455 HE
458 HE
KISIK
459 HE
MANAVGAT
48.000
143.0
Antalya
460 HE
MENZELET
124.000
603.0
K.Maras
461 HE
ÖZLÜCE
170.000
593.9
Elazig
462 HE
SARIYAR
160.000
310.1
Ankara
358.0
Samsun
113.0
Erzurum
Ankara
463 HE
SUAT UĞURLU
69.000
464 HE
TORTUM
26.200
465 HE
YENİCE
37.900
118.7
466 HE
BERKE
510.000
1,614.0
467 HE
SEYHAN I
60.000
447.1
Adana
468 HE
SEYHAN II
7.500
6.0
Adana
283.500
732.1
K.Maras
Osmaniye
469 HE
SIR
470 HE
KADINCIK I
70.000
200.0
Mersin
471 HE
KADINCIK II
56.000
175.0
Mersin
4.5
Adana
Antalya
472 HE
YÜREĞİR
6.000
473 HE
KEPEZ I-II
32.400
90.0
474 HE
OTHERS
45.000
100.0
475 HE
ADİLCEVAZ(MOSTAR EN.)
0.400
0.5
Bitlis
476 HE
AHLAT(MOSTAR EN.)
0.200
0.5
Bitlis
477 HE
BAYBURT(BOYDAK EN.)
0.400
1.7
Bayburt
478 HE
BESNİ(KAYSERİ VE CİVARI EN.ÜR.)
0.300
0.2
Adiyaman
BÜNYAN(KAYSERİ VE CİVARI)
1.200
3.2
Kayseri
14.400
22.0
Mardin
479 HE
480 HE
ÇAĞ-ÇAĞ(NAS EN.)
481 HE
ÇAMARDI(KAYSERİ VE CİVARI EN.ÜR.)
0.100
0.1
Nigde
482 HE
ÇEMİŞKEZEK(BOYDAK EN.)
0.100
0.5
Tunceli
483 HE
DEĞİRMENDERE(KA-FNIH EL.)
0.500
0.8
Osmaniye
484 HE
DERME(KAYSERİ VE CİVARI EN.ÜR.)
4.500
7.0
Malatya
485 HE
ERKENEK(KAYSERİ VE CİVARI EN.ÜR.)
0.300
0.5
Malatya
486 HE
GİRLEVİK(BOYDAK EN.)
3.000
19.0
Erzincan
487 HE
HAKKARİ (OTLUCA)((NAS EN.)
1.300
5.0
Hakkari
UNFCCC/CCNUCC
488 HE
Page 81
İNEGÖL(CERRAH)(KENT SOLAR EL.)
0.300
0.8
Bursa
489 HE
İZNİK (DEREKÖY)(KENT SOLAR EL.)
0.200
0.9
Bursa
490 HE
KARAÇAY(OSMANİYE)(KA-FNIH EL.)
KAYADİBİ(BARTIN)(İVME
ELEKTROMEKANİK
0.400
2.0
Osmaniye
0.500
2.0
Bartin
491 HE
492 HE
KERNEK(KAYSERİ VE CİVARI EN.ÜR.)
0.800
0.6
Malatya
493 HE
KOVADA-I(BATIÇİM EN.)
8.300
1.6
Isparta
494 HE
KOVADA-II(BATIÇİM EN.)
51.200
24.4
Isparta
1.0
Hatay
495 HE
KUZUCULU (DÖRTYOL)(KA-FNIH EL.)
0.300
496 HE
M.KEMALPAŞA(SUUÇTU)(KENT SOLAR EL.)
0.500
1.3
Bursa
497 HE
MALAZGİRT(MOSTAR EN.)
1.200
3.0
Mus
498 HE
PINARBAŞI(KAYSERİ VE CİVARI EN.ÜR.)
0.100
0.3
Kayseri
499 HE
SIZIR(KAYSERİ VE CİVARI EN.ÜR.)
5.800
35.0
Kayseri
500 HE
TURUNÇOVA(FİNİKE)(TURUNÇOVA EL.)
0.600
0.8
Antalya
501 HE
ULUDERE(NAS EN.)
0.600
2.6
Sirnak
502 HE
VARTO(MOSTAR EN.)
0.300
0.6
Mus
1,595.400
10,951.0
Sakarya
503 NG
GEBZE D.GAZ
504 NG
ADAPAZARI
797.700
5,473.0
Sakarya
505 NG
TRAKYA ELEKTRİK ENRON
498.700
3,797.0
Tekirdag
506 NG
ESENYURT (DOĞA)
188.500
1,400.0
Istanbul
507 NG
OVA ELEK.
258.400
2,019.0
Kocaeli
3,797.0
Tekirdag
Sanliurfa
508 NG
UNİMAR
504.000
509 HE
BİRECİK
672.000
2,092.0
510 HE
AHİKÖY I-II
4.200
21.0
Sivas
16.000
35.0
Burdur
511 HE
AKSU (ÇAYKÖY)
512 HE
ÇAL (LİMAK) (Denizli)
513 HE
ÇAMLICA (AYEN ENERJİ)
2.500
12.0
Denizli
84.000
429.0
Kayseri
3.000
16.0
Afyon
514 HE
DİNAR-II (METAK)
515 HE
FETHİYE
16.500
89.0
Mugla
516 HE
GAZİLER (Iğdır)
11.200
48.0
Igdir
517 HE
GİRLEVİK-II / MERCAN
11.000
39.0
Erzincan
518 HE
GÖNEN
10.600
47.0
Balıkesir
28.0
K.Maras
519 HE
SUÇATI (ERE EN.)
7.000
520 HE
SÜTCÜLER
2.300
13.0
Isparta
521 HE
TOHMA MEDİK (ALARKO)
12.500
59.0
Malatya
7.200
19.0
Izmir
10.200
31.0
Canakkale
Giresun
522 WD
ARES (ALAÇATI)
523 WD
BORES (BOZCAADA)
524 FO
AKSU SEKA (MİLDA KAĞIT)
8.000
20.0
148.300
1,038.1
ALBAYRAK TURİZM(BALIKESİR SEKA)
9.300
56.0
BOR ŞEKER
9.600
6.0
70.0
Zonguldak
Zonguldak
525 FO
ALİAĞA PETKİM
526 FO
527 FO
Izmir
Balikesir
Nigde
528 FO
OYKA KAĞ.(CAYCUMA SEKA)
10.000
529 FO
ERDEMİR
73.500
450.0
530 FO
HALKALI KAĞIT
5.100
39.0
Istanbul
531 FO
MED UNİON A.Ş. (EBSO)
3.400
26.9
Izmir
532 FO
MOPAK (Dalaman)
26.200
106.0
Mugla
35.0
Konya
533 FO
S.ŞEHİR (ETİ) ALÜMİNYUM
11.900
534 FO
TÜPRAŞ İZMİR (ALİAĞA RAF.)
44.000
306.0
Izmir
535 FO
TÜPRAŞ (İzmit-Yarımca)
45.000
291.2
Kocaeli
536 FO
TÜPRAŞ (Batman)
8.800
Batman
UNFCCC/CCNUCC
537 FO
538 FO
539 DO
Page 82
8.000
37.0
OTHERS (Isolated)
96.000
300.0
TÜPRAŞ (Batman)
10.300
72.0
0.100
1.0
TİRE-KUTSAN (Tire)
Izmir
Batman
540 DO
OTHERS
541 IC
ÇOLAKOĞLU-2
145.000
1,087.5
542 HC
İSDEMİR
220.400
772.0
Hatay
35.000
300.0
Zonguldak
Kocaeli
543 HC
KARDEMİR
544 LN
ALKİM (ALKALİ KİMYA) (Dazkırı)
2.500
17.0
Afyon
545 LN
PETLAS
6.000
40.0
Kirsehir
546 LN
MARMARA KAĞIT (Bilorsa)
2.000
9.0
Bilecik
547 LN
OTHERS
147.500
285.0
548 LPG
GOODYEAR (Adapazarı)
9.600
79.0
Sakarya
549 LPG
GOODYEAR (İzmit)
4.200
35.0
Kocaeli
550 LPG
MOPAK KAĞIT (Işıklar)
551 LPG
4.600
33.0
Izmir
65.0
Kayseri
ORTA ANADOLU MENSUCAT
10.000
552 NT
MENDERES TEKS. (AKÇA ENERJİ)
10.400
76.1
Denizli
553 NT
ALKİM KAĞIT
1.815
14.3
Afyon
554 NT
DENTAŞ (Denizli)
5.000
38.0
Denizli
555 NT
MENSA MENSUCAT
10.400
85.0
Adana
556 NT
TOROS (Ceyhan)
4.700
38.0
Adana
557 NT
TOROS (Mersin)
12.100
96.0
Mersin
558 NG
AKIN ENERJİ (B.Karıştıran)
4.900
37.0
Kirklareli
559 NG
ALTINYILDIZ (Yenibosna)
4.700
40.0
Istanbul
560 NG
ARÇELİK (Eskişehir)
6.300
49.0
Eskisehir
561 NG
ARÇELİK (Çayırova)
6.500
48.0
Kocaeli
7.0
Tekirdag
562 NG
ATLAS HALICILIK (Çorlu)
1.000
563 NG
1.000
8.3
Istanbul
564 NG
Tekirdag
4.300
33.0
565 NG
COGNİS (Tuzla)*
1.000
8.0
566 NG
ÇOLAKOĞLU-1
123.400
1,047.0
567 NG
DOĞUŞ (B.Karıştıran)
1.000
8.0
Tekirdag
568 NG
GÜLLE ENTEGRE (Çorlu)
6.300
29.0
Tekirdag
569 NG
İGSAŞ (Yarımca)
11.000
76.0
Kocaeli
570 NG
SANKO (İSKO) (İnegöl)
9.200
63.0
Bursa
157.0
Canakkale
Kocaeli
Izmir
Kocaeli
571 NG
KALESERAMİK (Çan Seramik+Kalebodur)
21.600
572 NG
KARTONSAN (İzmit)
24.000
192.0
7.0
Tekirdag
573 NG
NUR YILDIZ (GEM-TA)*
1.400
574 NG
SARKUYSAN (Tuzla)
7.700
60.0
Kocaeli
575 NG
SAMUR HALI A.Ş.
4.300
33.0
Ankara
34.0
Bilecik
576 NG
TERMAL SERAMİK (Söğüt)
4.600
577 NG
TRAKYA İPLİK (Çerkezköy)
4.200
29.0
Tekirdag
578 NG
Bursa
YILFERT (TÜGSAŞ GEMLİK GÜB.)
8.000
50.0
579 NG
TÜP MERSERİZE (B.Karıştıran)
1.000
7.0
Tekirdag
580 NG
YILDIZ SUNTA (Köseköy)
5.200
33.7
Kocaeli
581 NG
YONGAPAN (Kastamonu)
5.200
30.5
Kocaeli
84.100
296.0
582 NG
OTHERS
583 BG
BELKA (Ankara)
3.200
22.0
Ankara
584 BG
KEMERBURGAZ
4.000
7.0
Istanbul
10.000
57.0
Balikesir
540.000
1,170.0
585 BG
BANDIRMA BAĞFAŞ
586 HE
OYMAPINAR (ETİ ALİMİNYUM)
Antalya
UNFCCC/CCNUCC
587 HE
Page 83
BAĞCI SU ÜRÜNLERİ
0.300
1.7
588 HE
MOLU
3.400
10.6
Mugla
Kayseri
589 HE
YEŞİLLİLER (Kırşehir)
Kirsehir
0.500
1.0
70.200
398.1
Izmir
126.600
817.0
Bilecik
98.000
805.0
Tekirdag
ARENKO DENİZLİ
12.000
84.0
594 NG
AKIM EN. BAŞPINAR(SÜPER FİLM)G.ANTEP
25.300
177.0
Gaziantep
595 NG
AKSA AKRİLİK KİMYA (YALOVA)
59.500
450.0
Yalova
596 NG
BERK ENERJİ (BESLER -KURTKÖY)
10.400
73.1
Istanbul
597 NG
174.000
1,435.7
Bursa
600.5
Bursa
590 NT
ATAER ENERJİ (EBSO)
591 NG
AK ENERJİ (Bozüyük)
592 NG
AK ENERJİ (Çerkezköy)
593 NG
598 NG
Denizli
BOSEN (Bursa San.)
80.000
599 NG
BİL ENERJİ (Ankara)
36.600
255.0
Ankara
600 NG
EGE BİRLEŞİK ENERJİ
12.800
107.0
Izmir
CAM İŞ ELEKTRİK (B.Karıştıran)
32.900
270.0
Kirklareli
131.300
985.0
Samsun
601 NG
602 NG
CENGİZ ENERJİ ÇİFT YAK.
603 NG
DESA ENERJİ
604 NG
ENERJİ-SA (Adana)
605 NG
ENERJİ-SA (Çanakkale)
606 NG
ENERJİ-SA (Kentsa) Köseköy
607 NG
608 NG
ENTEK (Demirtaş)
609 NG
MAKSİ ENERJİ
610 NG
MODERN ENERJİ
611 NG
NUH ENERJİ 1 (Nuh Çimento)
612 NG
SAMSUN TEKKEKÖY (AKSA EN.)
613 NG
ŞAHİNLER ENERJİ(ÇORLU/TEKİRDAĞ)
614 NG
YENİ UŞAK ENERJİ
9.800
70.0
80.400
525.0
Izmir
Adana
42.525
345.0
Canakkale
120.000
930.0
Kocaeli
60.100
478.5
Kocaeli
104.000
784.2
Bursa
7.700
55.0
Istanbul
77.000
541.1
Tekirdag
38.000
326.0
Kocaeli
131.300
980.0
Samsun
22.800
162.2
Tekirdag
8.700
65.0
Usak
752.0
Bursa
615 NG
ZORLU ENERJİ (Bursa)
90.000
616 NG
65.800
494.1
Kirklareli
617 NG
ESKİŞEHİR ENDÜSTRİ ENERJİ(OSB)
59.000
451.8
Eskisehir
5.200
37.0
Kocaeli
618 WS
İZAYDAŞ (İzmit çöp)
619 FO
AKSA ENERJİ (Hakkari)
24.000
175.0
Hakkari
144.0
Bilecik
620 FO
HABAŞ (Bilecik)
18.000
621 FO
HABAŞ (İzmir)
36.000
288.0
Izmir
622 FO
KIZILTEPE
33.000
250.0
Mardin
623 FO
PS3-1 (SİLOPİ)
44.100
285.8
Sirnak
624 FO
PS3-2 (SİLOPİ)
29.500
191.2
Sirnak
625 FO
PS3-A -1
11.000
80.0
Sirnak
626 FO
PS3-A -2 (İDİL)
24.000
180.0
Sirnak
627 FO
SİİRT
24.000
190.0
Siirt
628 HE
BEREKET (DENİZLİ)
3.700
12.0
Denizli
143.2
Mugla
629 HE
BEREKET (DALAMAN)
30.000
630 HE
EŞEN-II (GÖLTAŞ)
21.700
40.0
Mugla
55.0
Sakarya
631 HE
KAREL (PAMUKOVA)
9.300
632 HE
MURGUL BAKIR
4.700
7.5
633 HE
Artvin
BEYKÖY ZORLU
16.800
87.0
Eskisehir
634 HE
KUZGUN ZORLU
20.900
0.0
Erzurum
635 HE
TERCAN ZORLU
15.000
28.0
Erzincan
636 HE
ATAKÖY ZORLU
5.500
8.0
Tokat
UNFCCC/CCNUCC
637 HE
Page 84
ÇILDIR ZORLU
15.400
20.0
Kars
638 HE
İKİZDERE ZORLU
18.600
100.0
Rize
639 WD
ALİZE ENERJİ (DELTA PLASTİK)
1.500
4.0
Izmir
TOTAL
49,468.3
256,636.4
51,327.3
20%
256,636,38
MWh
2
51,327,276 MWh
AEGtotal
AEGSET-=20 per cent
Abbreviations: AS: Asphaltite, BG: Biogas, DO: Diesel Oil, FO: Fuel Oil, GT: Geothermal, HC: Hard Coal, HE: Hydroelectric, IC:
Imported Coal, LN: Lignite, LPG: Liquefied Petroleum Gas, NG: Natural Gas, NT: Naphta, WD. Wind, WS: Waste
Appendix 5: Further background information on monitoring plan
Not available.
Appendix 6: Summary of post registration changes
Not available.
----History of the document
Version
04.1
Date
11 April 2012
04.0
EB 66
13 March 2012
EB 25, Annex 15
26 July 2006
02
EB 14, Annex 06b
14 June 2004
01
EB 05, Paragraph 12
03 August 2002
Decision Class: Regulatory
Document Type: Form
Business Function: Registration
Nature of revision
Editorial revision to change version 02 line in history box from Annex 06 to
Annex 06b.
Revision required to ensure consistency with the “Guidelines for completing
the project design document form for CDM project activities” (EB 66, Annex
8).
03
Initial adoption.

(GS) Other

Transkript

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