switch from single cycle to combined cycle (cc) cdm project at shirvan power plant
TRANSCRIPT
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PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03
CDM – Executive Board
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CLEAN DEVELOPMENT MECHANISM
PROJECT DESIGN DOCUMENT FORM (CDM-PDD)
Version 03 - in effect as of: 28 July 2006
CONTENTS
A. General description of project activity
B. Application of a baseline and monitoring methodology
C. Duration of the project activity / crediting period
D. Environmental impacts
E. Stakeholders’ comments
Annexes
Annex 1: Contact information on participants in the project activity
Annex 2: Information regarding public funding
Annex 3: Baseline information
Annex 4: Monitoring plan
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SECTION A. General description of project activity
A.1. Title of the project activity:
Switch from Single Cycle to Combined Cycle (CC) CDM Project at Shirvan Power Plant
PDD v.1.1
12/04/2011
A.2. Description of the project activity:
The proposed project activity consists in the conversion of an existing open cycle gas power plant to a
combined cycle gas power plant. The project activity is located close to the city of Shirvan, in North
Khorasan, Islamic Republic of Iran. The Shirvan power plant consists of 6 gas turbines, which are
divided in three different blocks. However, since only two blocks are being converted from open to
combined cycle, the project boundary will be limited to blocks one and two which are being converted
from open to combined cycle.
Purpose of the proposed project activity:
- Scenario existing prior to the start of the implementation of the project activity:
Blocks 1 and 2 of Shirvan power plant are currently operating with 4 gas turbines of 159 MW
gross capacity each under ISO conditions. The overall gross capacity of the two blocks is
therefore 636 MW under ISO conditions. Taking into account the site characteristics, the gross
capacity of the two blocks is 560 MW. The power plant is connected to the grid.
- Project scenario
The project activity consists in converting of block one and block two of the existing open cycle
power plant in Shirvan to a combined cycle power plant. For the conversion 4 heat recovery
steam generators (HRSG) and two steam turbines, each rated at 159 MW gross capacity under
ISO conditions, will be added. Overall, the proposed project activity will lead to an increase in
the gross capacity of block one and block two of the power plant from 636 MW to 954 MW
under ISO conditions. At site conditions, the combined cycle power plant will have a gross
capacity of 840 MW.
- Baseline scenario
The baseline scenario is equivalent to the continuation of the current practice, ie. the electricity
to meet the demand in the grid system will be generated:
1) By the operation of the existing power plant in open cycle mode;
2) By the operation of existing grid-connected power plants; and
3) By the addition of new generation sources to the grid.
Reduction of greenhouse gases:
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The conversion from open to combined cycle leads to significant efficiency gains, since the waste heat
from the existing gas turbines will be used to produce steam which will power the steam turbines. This
increase in efficiency will lead to an increase in the production of electricity, while keeping fossil fuel
consumption constant. The additional electricity produced will be supplied to the national grid, and will
displace other fossil fuel generated electricity, thereby reducing overall CO2 emissions. The project
activity is expected to reduce overall emissions of CO2 by 6,453,239t over 10 years (see section A.4.4 for
detailed values).
Contribution to sustainable development:
The proposed project activity contributes to sustainable development in Iran through a number of ways:
- More efficient use of Iran’s gas reserves: the efficiency gains achieved by the conversion from
open to combined cycle will help preserve finite fossil fuel resources
- Ensuring stable supplies of electricity: The proposed project activity will contribute to providing
stable power supplies to the population and industries of Iran, without increasing the
consumption of fossil fuels.
- Technology and know-how transfer: the proposed project activity will lead to training of the
local staff, and help the spread of modern power plant technology in Iran.
A.3. Project participants:
Name of Party involved ((host)
indicates a host Party)
Private and/or public entity(ies)
project participants (as
applicable)
Kindly indicate if the Party
involved wishes to be considered
as project participant (Yes/No)
Islamic Republic of Iran (host) Iran Power Development Company
(IPDC) (Project owner - Public
entity)
No
Switzerland Swiss Carbon Assets Ltd. (Carbon
consultant - Private entity)
No
Switzerland Energy Changes Projektentwicklung
GmbH (Carbon consultant - Private
entity)
No
A.4. Technical description of the project activity:
A.4.1. Location of the project activity:
A.4.1.1. Host Party(ies):
Islamic Republic of Iran
A.4.1.2. Region/State/Province etc.:
North Khorasan Province
A.4.1.3. City/Town/Community etc.:
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Shirvan
A.4.1.4. Details of physical location, including information allowing the
unique identification of this project activity (maximum one page):
Shirvan is located in the province of North Khorasan, in north-eastern Iran, as shown on the map below:
The power plant is located on Shirvan-Mashad Road 12 kilometres from Shirvan, in North Khorasan
Province.
Geographical coordinates:
- Site latitude:37 degrees, 0 minutes and 22 seconds North
- Site longitude: 58 degrees, 2 minute and 34 seconds East
- Site altitude: 1160 meters
Location of power plant
Shirvan
Shirvan
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A.4.2. Category(ies) of project activity:
Energy industries (non-renewable sources), sectoral scope 1.
A.4.3. Technology to be employed by the project activity:
Scenario existing prior to the start of the implementation of the project activity:
The existing Shirvan power plant consists of 6 units of Ansaldo – v94.2 gas turbines, arranged in three
blocks. The turbines have a gross installed capacity of 159 MW per unit at ISO conditions, with a net
capacity per unit of 158.667 MW at ISO conditions. Two gas turbines together form one block. The
Ansaldo – v94.2 gas turbines achieve 31% – 34% efficiency, and are designed for a life time of 25 years.
The 4 gas units from block one and two were synchronized on the following dates:
- Unit 1: March 16 2006
- Unit 2: May 10 2006
- Unit 3: July 5 2006
- Unit 4: September 6 2006
The proposed project activity includes the addition of:
- Four heat recovery steam generators (HRSGs), one per gas turbine in the first two blocks of the
power plant
- Two steam turbine-generator in blocks one and two
The particulars of the steam turbines:
SIEMENS-E30-16-1*6.3-7 Model
2 Number Of Units
159(With SF) Nominal Capacity Per Unit (MW)
153.8 Rated Net Capacity Per Unit (MW)
25 Design Life Time (yr)
The particulars of the steam turbine generators:
2 Number Of Units
200,000 Output Power Per Unit (KVA)
SALIENT Kind Of Rotor
3000 Rated Speed (RPM)
0.8 Power Factor
7331 Current (A)
15750 Voltage (V)
50 Frequency (Hz)
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With the proposed project activity, the gross installed capacity of block one and two of Shirvan power
plant will increase to 954 MW at ISO conditions – an increase of 50%. The nameplate efficiency of the
power plant will increase to 49% - 51%.
The fuel consumption will be measured by turbine gas flow meters (for natural gas) or turbine oil flow
meters (for diesel) respectively. Electricity meters measuring the amount of electricity produced by the
generators and the auxiliary consumption of the power plant will be installed. All meters will be subject
to regular maintenance in line with manufacturer or industry standards.
The baseline scenario is the same as the scenario existing prior to the start of the implementation of the
project activity (i.e. continuation of current practice).
Involved greenhouse gases: CO2.
For calculation of expected emission reductions the following yearly energy and mass flows are assumed.
The consumption of diesel and natural gas are not expected to increase compared to the current situation.
Year EGCC,y FCDiesel, y (lit) FCNG, y (Nm3)
1 2,618,429 55,795,231 424,413,371
2 2,607,955 55,572,050 422,715,718
3 2,597,523 55,349,762 421,024,855
4 2,587,133 55,128,363 419,340,755
5 2,576,785 54,907,850 417,663,392
6 2,566,478 54,688,218 415,992,739
7 2,556,212 54,469,465 414,328,768
8 2,545,987 54,251,587 412,671,453
9 2,535,803 54,034,581 411,020,767
10 2,525,660 53,818,443 409,376,684
A.4.4. Estimated amount of emission reductions over the chosen crediting period:
Years Annual estimation of emission reductions
in tonnes of CO2 e
1 655,793
2 653,443
3 651,102
4 648,771
5 646,449
6 644,136
7 641,833
8 639,539
9 637,254
10 634,919
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Total estimated reductions (tonnes of CO2e) 6,453,239
Total number of crediting years 10
Annual average over the crediting period of
estimated reductions (tonnes of CO2 e)
645,324
A.4.5. Public funding of the project activity:
There is no public funding for the project activity.
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SECTION B. Application of a baseline and monitoring methodology
B.1. Title and reference of the approved baseline and monitoring methodology applied to the
project activity:
ACM0007 Version 04, “Consolidated methodology for conversion from single cycle to combined cycle
power generation”
“Tool to calculate the emission factor for an electricity system”, Version 2
“Tool to determine the remaining lifetime of equipment”, Version 1
“Combined tool to identify the baseline scenario and demonstrate additionality”, Version 2.2
“Tool to calculate project or leakage CO2 emissions from fossil fuel combustion”, Version 2
B.2. Justification of the choice of the methodology and why it is applicable to the project
activity:
Applicability criteria of the methodology ACM0007, Version 04
This methodology applies to project activities that utilize previously-unused waste heat from a power
plant, with a single-cycle capacity, be it a gas turbine or an internal combustion engine and utilize the
heat to produce steam for a turbine thus making the system combined-cycle.
The proposed project activity involves the conversion of block one and block two at the grid connected
power plant in Shirvan from single-cycle to combined-cycle mode. It will use previously unused waste
heat from the power plant to power the steam turbines.
Waste heat generated on site is not utilizable for any other purpose on-site
Waste heat cannot be used for other purposes on site, since no other source of demand if located nearby.
The project activity does not increase the lifetime of the existing gas turbine or engine during the
crediting period, determined using the “Tool to determine the remaining lifetime of equipment”;
The project does not involve any upgrade or modification to the existing gas turbines themselves.
Therefore, the conversion does not affect the lifetime of the installed equipment. The gas turbines have a
lifetime of 25 years, as indicated in official documentation by the manufacturer. This is in line with the
“Tool to determine the remaining lifetime of equipment”, Version 1.
The table below shows the commissioning dates of the different gas turbines and the expected end-date
of the lifetime of the gas turbines:
Number of power unit Number of gas turbine Synchronization date End-date of lifetime
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of gas turbine
Block 1 Gas turbine 1 16.03.2006 16.03.2031
Gas turbine 2 10.05.2006 10.05.2031
Block 2 Gas turbine 3 05.07.2006 05.07.2031
Gas turbine 4 06.09.2006 06.09.2031
The project has a crediting period of 10 years. Therefore, the installed equipment will not reach the end
of its lifetime during the crediting period.
Project developers have access to appropriate data to estimate the combined margin emission factor, as
described in the “Tool to calculate the emission factor for an electricity system”, of the electricity grid to
which the proposed project is connected
The project developers have access to the appropriate data. The combined margin emission factor was
calculated as described in the “Tool to calculate the emission factor for an electricity system”, Version
02. See section B.6.3 below.
B.3. Description of the sources and gases included in the project boundary:
The spatial extent of the project boundary includes the power plant at the project site and all power
plants considered for the calculation of the baseline CO2 emission factor. A flow diagram of the project
boundary, physically delineating the project activity is presented below:
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The following table illustrates which emissions sources are included and which are excluded from the
project boundary for determination of both baseline and project emissions.
Source Gas Included? Justification / Explanation
Baseline
Scenario Baseline: Grid
electricity generation
CO2 Yes Main emission source
CH4 No Excluded for simplification. This is conservative
N2O No Excluded for simplification. This is conservative
On-site fossil fuel
consumption to operate
project power plant in
CO2 Yes An important emission source
CH4 No Excluded for simplification. This emission source is
assumed to be very small
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open cycle mode. N2O No Excluded for simplification. This emission source is
assumed to be very small
Project Activity
On-site fossil fuel
consumption to operate
the gas turbine or
engine of project power
plant.
CO2 Yes An important emission source
CH4 No Excluded for simplification. This emission source is
assumed to be very small
N2O No Excluded for simplification. This emission source is
assumed to be very small
On-site fossil fuel
consumption to
supplement waste heat
in operating Steam
turbine.
CO2 Yes May be an important emission source
CH4 No Excluded for simplification. This emission source is
assumed to be very small
N2O No Excluded for simplification. This emission source is
assumed to be very small
B.4. Description of how the baseline scenario is identified and description of the identified
baseline scenario:
In line with the requirements of ACM0007 Version 04, the “Combined tool to identify the baseline
scenario and demonstrate additionality” Version 2.2 is used to determine the baseline.
Step 1: Identification of alternative scenarios
This step serves to identify all alternative scenarios to the proposed CDM project activity that can be
then baseline scenario through the following Sub-steps:
Step 1a: Define alternative scenarios to the proposed CDM project activity
Identify all alternative scenarios that are available to the project participants and that provide outputs
or services with comparable quality, properties and application areas as the proposed CDM project
activity. These alternative scenarios shall include:
- The proposed project activity undertaken without being registered as a CDM project activity
Description of Alternative Plausibility Check
The project activity (i.e switch from
open to combined cycle at block one
and block two of the power plant) not
implemented as a CDM project
Delivers comparable output as project activity.
Is available to IPDC (a project participant).
� Plausible but not financially attractive (see step 3)
- All other plausible and credible alternative scenarios to the project activity scenario, including
the common practices in the relevant sector, that deliver outputs or services (e.g. electricity, heat
or cement) with comparable quality, properties and application areas, taking into account,
where relevant, examples of scenarios identified in the underlying methodology;
The tool gives further guidance that credible alternative scenarios shall:
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- be situated in the Islamic Republic of Iran
- be available to the project participants
New power plants using technologies other than the one used in the project activity, which attain a
similar scale than the proposed project activity:
Description of Alternative Plausibility Check
Open cycle Medium-Large Gas Turbine
Technical lifetime up to 20 years
Efficiency up to 34.5%
Source: Information provided by
Ministry of Energy of Iran
Can deliver comparable output as project activity, subject to
fuel availability.
Is available to IPDC (a project participant).
� Plausible, but faces fuel availability barrier (see step
2).
Steam Plant (using residual fuel oil and
natural gas)
Technical lifetime: 30 years
Source: World Bank Iran Power Sector
Note
Efficiency: up to 37-39%
Source: UNFCCC-Tool: Tool to
calculate the emission factor for an
electricity system
Can deliver comparable output as project activity, subject to
fuel availability.
Is not available to IPDC (a project participant), since not being
developed anymore due to high capital costs and lead times in
construction.
Not plausible => excluded.
Coal Power Plant
Technical lifetime: 40 years
Source: OECD study - Projected costs
of generating electricity 2005 update
Efficiency: 37-50%
Source: UNFCCC-Tool: Tool to
calculate the emission factor for an
electricity
Can deliver comparable output as project activity, subject to
fuel availability.
Is not available to IPDC (a project participant), since no coal
fired power plants have been developed in Iran.
Not plausible => excluded.
Diesel Oil Power Plant
Technical lifetime: 20 years
Source: OECD study - Projected costs
of generating electricity 2005 update
Efficiency: 30-46%
Source: UNFCCC-Tool: Tool to
calculate the emission factor for an
electricity system
Cannot deliver comparable output as project activity, since
diesel oil power plants are built at much lower capacity1.
Is available to IPDC (a project participant).
Not plausible => excluded.
Nuclear Power
Technical lifetime: 60 years
Delivers comparable output as project activity.
1 The largest diesel oil power plant ever built in Iran has a capacity of 125 MW, less than 50% than the proposed
project activity. No more diesel power plants have been built since 1992 in Iran.
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Efficiency: 36%
Source: IEA Energy Technology
Essentials – Nuclear power
http://www.iea.org/techno/essentials4.p
df
Is not available to IPDC (a project participant), since nuclear
power plant at Bushehr is developed by the Atomic Energy
Organization of Iran (AEOI).
Not plausible => excluded.
Large hydropower plant
Technical lifetime (up to 100 years)
Efficiency 34% - 56%
Source: IEA Energy Technology
Network http://www.etsap.org/E-
techDS/PDF/E07-hydropower-GS-
gct.pdf
Can deliver comparable output as project activity, if big
enough reservoir to supply base-load electricity.
Is not available to IPDC (a project participant), since hydro
power plants in Iran are developed by either Iran Water and
Power Resources Development Co. (IWPCO) or the
Khuzestan Water & Power Authority (KWPA)
Not plausible => excluded.
Wind
Technical lifetime: 25 years
Source: OECD study Emission
baselines estimating the unknown
/2000
Efficiency: up to 40%
Source:
http://en.wikipedia.org/wiki/Wind_powe
r#Capacity_factor
Does not deliver comparable output as project activity, since
wind farms are an intermittent source of power. Therefore
wind farms cannot be used to displace base load capacity.
Is available to IPDC.
Not plausible => excluded.
- If applicable, continuation of the current situation and, where relevant, the “proposed project
activity undertaken without being registered as a CDM project activity” undertaken at a later
point in time (e.g. due to existing regulations, end-of-life of existing equipment, financing
aspects).
Description of Alternative Plausibility Check
Continuation of the current practice, ie.
that to meet the demand in the grid
system the electricity will be generated:
1) By the operation of the existing
power plant in open cycle
mode;
2) By the operation of existing
grid-connected power plants;
and
3) By the addition of new
generation sources to the grid
Delivers comparable output as project activity.
Is available to IPDC (a project participant).
� Plausible
Outcome of Step 1a: List of plausible alternative scenarios to the project activity
Scenario Title of Alternative
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1 The project activity (i.e switch from open to combined cycle at block one and
block two of the power plant) not implemented as a CDM project
2 Open cycle Medium-Large Gas Turbine
3 Continuation of the current practice
Sub-step 1b: Consistency with mandatory applicable laws and regulations
The alternative(s) shall be in compliance with all mandatory applicable legal and regulatory
requirements.
In addition, the methodology ACM0007 v.04 specifies explicitly that the following regulations should be
taken into account:
• Regulations for utilization of waste heat on the premises where it is generated;
No regulations for the utilization of waste heat on the premises exist.
• Regulation on energy efficiency norms for power projects; and
No regulation on energy efficiency norms for power plants exists. Open cycle and combined
cycle power plants continue to operate in Iran, showing that they satisfy all existing energy
efficiency norms for power plants.
Emission norms for power projects.
Open cycle and combined cycle power plants continue to operate in Iran, showing that they
satisfy all existing emission norms for power plants.
No other mandatory applicable laws and regulations exist which could exclude any of the plausible
alternative scenarios.
Outcome of Step 1b: List of alternative scenarios to the project activity that are in compliance with
mandatory legislation and regulations […].
Scenario Title of Alternative
1 The project activity (i.e switch from open to combined cycle at block one and
block two of the power plant) not implemented as a CDM project
2 Open cycle Medium-Large Gas Turbine
3 Continuation of the current practice
Step 2: Barrier analysis
This Step serves to identify barriers and to assess which alternatives are prevented by these barriers.
Apply the following Sub-steps:
Sub-step 2a: Identify barriers that would prevent the implementation of alternative scenarios
Establish a complete list of realistic and credible barriers that may prevent alternative scenarios to
occur.
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Description of Barrier Plausibility Check
Technological barriers:
Access to fuel
Access to fuel is determined by locally available infrastructure and the
supply contracts entered into with the fuel supplier. Shirvan power plant is
connected to the gas network, but the gas supply contract stipulates a
maximum delivery of 300,000 Nm3 of natural gas per hour. This means that
the maximum available supply of natural gas for Shirvan power plant is
effectively capped. This limits possible capacity extensions for natural gas
fired power plants such as open cycle power plants.
Despite having the second largest gas reserves in the world, gas is becoming
seasonally scarce in Iran because of i) very low domestic gas price which
encourages overconsumption, ii) lack of investment in pipeline
infrastructure and storage that leads to local supply bottlenecks and iii)
underinvestment in gas exploration and extraction2. This has lead to power
plants using diesel in times of high demand of residential gas consumption
(ie. during the winter). This shows that there are severe limitations on how
much additional natural gas can be made available.
Outcome of Step 2a: List of barriers that may prevent one or more alternative scenarios to occur
- Access to fuel barrier
Sub-step 2b: Eliminate alternative scenarios which are prevented by the identified barriers
The following table shows through which factors the identified barriers affect power plant projects:
Barrier Indicators for barriers Explanation
Access to fuel
barrier
Electricity production per
unit of natural gas
(MWh/Nm3)
Due to the relative scarcity of natural gas and the limits
imposed by the gas supply contract for Shirvan Power
Plant, power plants which cannot deliver the equivalent
output as the combined cycle under the existing gas
supply contract will be excluded.
This will allow us to analyze which barrier is affecting which alternative.
Applicability of the different barriers to the scenarios:
Barrier &
indicator
Scenario 1:
project
activity
without CDM
Scenario 2:
open cycle
Scenario 3:
current
practice
Access to fuel
barrier
No additional
fuel needed
Yes,
insufficient gas
available
No additional
fuel needed
2 See World Bank Power Sector Note, p. 20 - 21
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Access to fuel barrier:
Scenario 2: Open cycle power plant requires significant additional natural gas resources to be available.
As explained, gas in general is becoming scarcer in Iran and the local supply of natural gas in Shirvan is
limited by the existing gas supply contract. This contract stipulates that up to 300,000 Nm3 of natural gas
are available in Shirvan. This amount of natural gas is insufficient to increase the capacity at the site by
the same amount as in the proposed project activity.
The efficiency of the existing gas turbines are as follows:
Year Energy input (GJ) Electricity output GJ Efficiency
21/3/2007-20/3/2008 12,735,650 3,766,514 29.57%
21/3/2008-20/3/2009 25,018,172 7,630,996 30.50%
21/3/2009-20/3/2010 22,063,760 6,802,877 30.83%
Average 19,939,194 6,066,796 30.30%
An efficiency of 30.30% implies that when the open cycle power plant is running at full load (840 MW
site conditions), it consumes 258,864 Nm3 of natural gas. Therefore, compared to the amount stipulated
in the contract, only a surplus of 41,136 Nm3 natural gas per hour is available, which limits the
additional capacity that can be installed on site.
Maximum additional capacity that can be installed with 41,136 Nm3 natural gas per hour:
Scenario 2: Open cycle
Additional amount of natural gas
available (Nm3)
41,136
Efficiency % 30.30%
Maximum additional capacity (MW) 133
% of additional capacity installed under
proposed project activity (266 MW)
48%
This clearly shows that Scenario 2 would not deliver equivalent outputs to the proposed project activity
due to the limited amount of fuel available. Hence open cycle gas turbines are prevented by an access to
fuel barrier.
Outcome of Step 2: List of alternative scenarios to the project activity which are not prevented by any
barrier
Scenario Title of Alternative
1 The project activity (i.e switch from open to combined cycle at block one and
block two of the power plant) not implemented as a CDM project
3 Continuation of the current practice
If there are still several alternative scenarios remaining, including the proposed project activity
undertaken without being registered as a CDM project activity, proceed to Step 3 (investment analysis).
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Step 3: Investment analysis
This Step serves to determine which of the alternative scenarios in the short list remaining after Step 2 is
the most economically or financially attractive. For this purpose, an investment comparison analysis is
conducted for the remaining alternative scenarios after Step 2. If the investment analysis is conclusive,
the economically or financially most attractive alternative scenario is considered as the baseline
scenario.
Since the continuation of current practice does not involve an investment on behalf of the project
proponent, a benchmark analysis is conducted. The IRR is chosen as a suitable financial indicator, since
it allows assessing whether a single project activity is financially attractive or not.
The national benchmark for investments in power plants as confirmed by the Ministry of Energy in Iran
is used. It is equal to 20%. The financial analysis is done over the period of conversion and operation of
the power plant. Only costs and revenues which are due to the conversions from open to combined cycle
power plant are taken into account.
The relevant data for calculation of the IRR are tabulated below:
Parameter (unit) Value combined
cycle
Source
Generated Electricity & fuel consumption
Nominal capacity ISO (MW) 318 IPDC – MAPNA
contract
Capacity at site condition (MW) 280 Ministry of
Energy
Degradation (%) 0.40% World Bank Iran
Power Sector
Note
Operating hours (%) 3168 Operating hours
open cycle
plant3
Auxiliary consumption (%) 1.60% World Bank Iran
Power Sector
Note
Costs
Investment costs per unit (EUR) 108,889,182 IPDC – MAPNA
contract
Investment costs per unit (USD) 9,689,964 IPDC – MAPNA
contract
Investment costs per unit (IRR) 1,099,490,909,09
2
IPDC – MAPNA
contract
Operation and maintenance costs
(USD/MWh)
0.69 World Bank Iran
Power Sector
Note
3 Based on historical data
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Electricity price (IRR/KWh) August
2007 144
Iran Grid
Management
Company
Timeline
Construction time (years) 3 Ministry of
Energy
Technical lifetime (years) 20 Ministry of
Energy
Economic indicators
Exchange rate IRR/EUR 12.8.2007 12453.3 www.oanda.co
m
Exchange rate USD/EUR 12.8.2007 1.3689 www.oanda.co
m
Inflation rate 7%
Annual
electricity price
inflation 2006 &
first half 2007
Benchmark 20%
Ministry of
Energy
The result of the financial analysis is provided below.
IRR Benchmark
Base case 5.75% 20%
As can be seen, the proposed project activity is clearly not financially attractive, thereby reinforcing the
conclusion reached in Step 2 above.
A sensitivity analysis is conducted to see if this result is robust to reasonable variations in the underlying
assumptions. In line with the Guidance on the Assessment of Investment Analysis (version 2), all
parameters which constitute either more than 20% of either total project cost or total project revenues are
subjected to reasonable variation of either +10% or -10%.
The following parameters constitute more than 20% of either total project cost or total project revenues:
% of total costs/revenues
Investment Costs 91%
Electricity tariff 100%
In addition, operating hours and inflation rate were also subjected to the same sensitivity analysis, since
they have an indirect impact on either total project costs or revenues which exceeds 20%.
The results of the sensitivity analysis are shown below:
Scenario 1 - Investment IRR Benchmark
10% 4.91% 20%
-10% 6.70% 20%
Scenario 2 - Operating hours
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10% 6.61% 20%
-10% 4.83% 20%
Scenario 3 - Electricity tariff
10% 6.65% 20%
-10% 4.78% 20%
Scenario 4 - Inflation
10% 6.40% 20%
-10% 5.09% 20%
The sensitivity analysis confirms the outcome of the benchmark analysis. This clearly shows that
Scenario 1: Project activity without CDM is not a plausible baseline scenario. Hence, Scenario 3: Current
practice is the only remaining alternative.
The result that combined cycle power plants are not an attractive investment in Iran without CDM is
confirmed by the results of the World Bank Iran Power Sector Note. This document shows that combined
cycle power plants without CDM are not cost competitive in Iran, mainly because of the very low price
of natural gas. This confirms the outcome of our benchmark analysis.
In addition to the requirements of the Combined tool to identify the baseline scenario and demonstrate
additionality Version 2.2, the methodology ACM007 Version 4 mentions the following points:
When the current practice condition (to continue the operation in open cycle) is assessed, the future
estimated load factor should reflect the changes due to new conditions in the grid, analyzing the last
plants that have been incorporated in the grid.
A change in the future estimated load factor for the current practice condition would have no impact on
either the barrier analysis (Step 2) or the benchmark analysis (Step 3) conducted above.
Project proponents, if undertaking investment analysis, shall include the revenue generated from the
possible increase in electricity produced from the open cycle component in the project situation.
The operating hours of the existing open cycle power plant are equal to 3168 hours of full load. This
shows that the power plant is operated to supply base load electricity to the grid4. Therefore no further
increase in operating hours is anticipated.
If the sensitivity analysis confirms the result of the investment comparison analysis, then the most
economically or financially attractive alternative scenario is considered as baseline scenario.
Therefore the Scenario 3: continuation of current practice constitutes the baseline scenario.
Finally, the methodology ACM0007 Version 4 specifies one more applicability condition:
This methodology is only applicable where it can be demonstrated that the baseline scenario is the
continuation of the current practice, i.e. that in the absence of the proposed project activity the
electricity, to meet the demand in the grid system, will be generated:
4 ACM0013 defines base load as more than 3,000 hours per year.
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(1) By the operation of the existing power plant in open cycle mode;
(2) By the operation of existing grid-connected power plants; and
(3) By the addition of new generation sources to the grid.
As is demonstrated in this section, the baseline scenario is the continuation of the current practice
(Scenario 3). Therefore the methodology ACM0007 Version 4 is applicable.
Step 4: Common practice analysis
This test is a credibility check to demonstrate additionality which complements the barrier analysis (Step
2) and, where applicable, the investment analysis (Step 3).
Establish list of similar activities
Provide an analysis to which extent similar activities to the proposed CDM project activity have been
implemented previously or are currently underway. Similar activities are defined as activities (i.e.
technologies or practices) that are of similar scale, take place in a comparable environment, inter alia,
with respect to the regulatory framework, and are undertaken in the relevant geographical area
The following table gives an overview of the criteria a power plant needs to fulfil in order to be
considered similar to the proposed project activity, as defined in the Combined tool to identify the
baseline scenario and demonstrate additionality Version 2.2:
Criteria Similar Not similar
Technology Conversions from open to
combined cycle power plants
Greenfield combined cycle power plants
Integrated solar combined cycle power plants
Open cycle gas power plants
Steam power plants
Coal power plants
Diesel power plants
Nuclear power plants
Hydro power plants
Wind power plants
Scale 954 MW power plants, +/- 30%
capacity
Power plants smaller than 668 MW and larger than
1240 MW installed capacity
Comparable
environment
- Project start under the
Ministerial Order
Establishing the Electricity
Market, issued on August 25
2005
- Owned by Tavanir, the
electricity holding company
- Project start before August 25 2005, ie. in a
different regulatory framework
- Project developed as Build Own Operate (BOO)
or BOT (Build Own Transfer) and owned by
private investors
Relevant
geographical
area
Islamic Republic of Iran Other country
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Background on regulatory framework of Iranian power market5
a) Establishment of a competitive power market
The Ministerial Order Establishing the Electricity Market issued on 16 August 2005 is the key
legislative piece used by the authorities to establish a new market based power sector in Iran. The
Ministerial Order contains, inter alia, the following provisions:
o market rules that create a two-tier structure for electricity sale and purchase transaction,
including a centrally scheduled and dispatched operational regime for Tavanir owned
power plants and a semi-centrally scheduled and dispatched regime for independent
power producers.
o creation of the regulatory agency, the Electricity Market Regulatory Board (EMRB),
which oversees the operation of the market rules
o identification of mechanisms by which the Iran Grid Management Company (IGMC)
controls the market transactions.
As a result, power plants now need to bid in a competitive market to supply their electricity to
the grid. Before the Ministerial Order no power market existed and there was not even an
electricity price paid to the power plants for electricity supplied to the grid. Construction of
power plants, supply and distribution of electricity were centrally decided based on non-market
mechanisms.
b) Encouraging private participation in the power market
Based on the fourth Five Year Development Plan (FYDP) adopted in 2004, private investments
in power generation facilities are encouraged. Previously private participation in the electricity
sector was excluded.
Several options exist to private developers, but to-date all IPPs have signed so called Energy
Conversion Agreements (ECAs) with Tavanir. These ECAs supply the power plants with free
natural gas, against a fixed off-take electricity price. Two different schemes exist, so called Build
Own Operate (BOO) and Build Own Transfer (BOT), with BOOs typically targeted at domestic
investors and BOTs targeted at foreign investors.
Since natural gas is supplied for free during the lifetime of the project (typically 20 years), the
electricity price paid under ECAs is different from the electricity price which is settled in the
power pool. Hence the institutional setup for and risks faced by privately owned power plants are
very different from power plants owned by the Ministry of Energy.
Combining the elements outlined in the table above, a combined cycle power plant needs to fulfil the
following criteria in order to be considered similar with the proposed project activity:
- Conversion from open to combined cycle power plant6
- installed capacity between 668 MW and 1240 MW
- owned by Tavanir
- project start date after August 25 2005
5 The following is heavily based on Chapter 5 and Chapter 7 of the Iran Power Sector Note
6 The same definition as in ACM0007 Version 4 will be applied to distinguish greenfield combined cycle power
plants from conversions, namely an operational history of at least 3 years.
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The below list of all combined cycle power plants already built or under construction in Iran will check
to what extent the combined cycle power plants fulfil these criteria. Since commissioning dates are easier
to obtain than project start dates, in a first step power plants with a commissioning date prior to August
25 2005, with an incorrect size or which are not owned by the MoE will be excluded.
List of all combined cycle projects already constructed or undergoing construction in Iran:
Name of combined
Cycle Power Plant
Greenfield
or
conversion?
Installed
capacity
(MW)
Similar capacity?
(668MW -
1240MW)
Owned
by MoE?
Commissiong
date Similar?
Gilan conversion 1305.6 No MoE 17/06/1997 No
Qom conversion 714 Yes MoE 20/02/1998 No
Montazer-Ghaem (Karaj) conversion 997.5 Yes MoE 21/11/2000 No
Shahid Rajaee conversion 1042.8 Yes MoE 22/01/2002 No
Khoy conversion 349.3 No MoE 25/05/2002 No
Fars conversion 1035.3 Yes MoE 08/02/2003 No
Shariati conversion 346.8 No MoE 02/04/2003 No
Neishabour conversion 1040.4 Yes MoE 24/07/2003 No
Neka (Shahid Salimi) conversion 435 No MoE 17/07/2006 No
Yazd conversion 724.8 Yes MoE 01/01/2007 Maybe
Kazeroon conversion 1372 No MoE 19/12/2007 No
Kerman conversion 1912 No MoE 15/03/2009 No
Damavand conversion 2388 No MoE 2011 expected No
Sanandaj conversion 954 Yes MoE 2011 expected Maybe
Genaveh greenfield 484 No BOO 2011 expected No
South Esfahan conversion 968 Yes BOT 2011 expected No
Abadan conversion 954 Yes MoE 2011 expected Maybe
Jahrom conversion 1431 No MoE 2012 expected No
Pareh-sar greenfield 968 Yes BOO 2012 expected No
The above analysis shows that only three power plants might be considered similar:
- Yazd Combined Cycle Power Plant
- Abadan Combined Cycle Power Plant
- Sanandaj Combined Cycle Power Plant
To establish whether they can be considered similar we need to determine if their starting date predates
the issuance of the Ministerial Order of August 16 2005. The actual starting dates are as follows:
- Yazd Combined Cycle Power Plant: September 10 2002
- Abadan Combined Cycle Power Plant: May 4 2008
- Sanandaj Combined Cycle Power Plant: October 1 2007
Based on this only Abadan Combined Cycle Power Plant and Sanandaj Combined Cycle Power Plant can
be considered similar activities.
Essential distinctions between Abadan Combined Cycle Power Plant and the proposed project activity:
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The Abadan power plant received foreign funding from the Islamic Development Bank (IDB)7. Shirvan
does not benefit from any foreign funding.
CDM development:
All three similar power plants are being developed as CDM projects.
Therefore, sub-step 4 is satisfied; similar activities are observed but essential distinctions between the
proposed project activity and similar activities were reasonably explained. Hence the proposed project
activity is additional.
B.5. Description of how the anthropogenic emissions of GHG by sources are reduced below
those that would have occurred in the absence of the registered CDM project activity (assessment
and demonstration of additionality):
Additionality has been demonstrated in B.4, using the latest approved version of the “Combined tool to
identify the baseline scenario and demonstrate additionality”, Version 2.2.
Since the starting date of the project activity is before the date of validation, evidence is provided that the
incentive from the CDM was seriously considered in the decision to proceed with the project activity:
Date Development of conversion
from open to combined cycle
project
Activities taken to achieve
CDM registration
Evidence
September 5
2006
Minutes of meetings of internal
discussions about starting the
proposed project activity. IPDC
faces financial difficulties.
IPDC –
MAPNA
Agreement
including
Annexes,
Minutes of
meetings.
November
2006
Implementation of the Iranian
Designated National Authority
March 3 2007 Letter from IPDC to Ministry of
Energy to inquire about
possibility for additional funds
for the proposed project activity
to alleviate financing
difficulties.
Letter
April 10 2007 Letter from Ministry of Energy
to IPDC confirming the
possibility to receive additional
funding through CDM.
Introduction of IPDC to Dr.
Letter
7 http://www.uzdaily.com/articles-id-2825.htm
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Parviz Nikkhah, a CDM expert.
August 12
2007
Letter from IPDC to MAPNA
announcing the start of the
proposed project activity and
IPDC’s intention to register the
conversions as a CDM project =
Investment start date
Letter
October 1
2007
First payment for the proposed
project activity = Project start
date
Proof of
payment
November 13
2007
First meeting between IPDC,
Energy Changes (a CDM
consultant) and Dr. Parviz
Nikkhah. A draft CDM
agreement is submitted from
Energy Changes to IPDC.
Letter, draft
CDM
agreement
December 11
2007
Meeting legal department IPDC
with Energy Changes & Dr.
Parviz Nikkhah to discuss draft
CDM agreement
Minutes
September 20
2008
Letter from Chairman of IPDC
to deputy Energy Minister
asking for authorization for
signing CDM contract
Letter
September 28
2008
Confirmation by MAPNA to
IPDC that the proposed project
activity started.
June 6 2009 Hand-over of land from Tavanir
to MAPNA to develop the
proposed project activity
Minutes of
meeting
August 1 2009 Letter of Ministry of Energy to
Economic council concerning
IPDC’s responsibility for the
CDM and combined cycle
projects
Letter
April 25 2010 Confirmation of IPDC’s
responsibility for CDM
development by Economic
Council
Letter
August 4 2010 CDM contract signing IPDC -
Carbon Tejarat Iranian
CDM contract
January 7 2011 Agreement Carbon Tejarat
Iranian, Energy Changes &
Swiss Carbon Assets to jointly
develop the CDM project
activity
Agreement
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April 11 2011 Signing of DOE contract for
project activity
DOE contract
August 2012 Expected commissioning of
steam unit 1
November
2012
Expected commissioning of
steam unit 2
B.6. Emission reductions:
B.6.1. Explanation of methodological choices:
In accordance with ACM007 version 4, the project activity mainly reduces CO2 emissions through
substitution of power generation supplied by the existing generation sources connected to the grid and
likely future additions to the grid. The relevant methodological steps are described below:
Emission reductions
The emission reductions (ERy) can be expressed as follows:
yyyy LEPEBEER −−= (1)
Where:
ERy = Emissions reductions in year y (tCO2)
BEy = Baseline emissions in year y (tCO2)
PEy = Project emissions in year y (tCO2)
LEy = Leakage emissions in year y (tCO2)
Project emissions
Project emissions (PEy) should be calculated based on “Tool to calculate project or leakage CO2
emissions from fossil fuel combustion” and is referred to in the Tool as PEFC,j,y, making the element
processes j correspond to the combustion of fossil fuels in year y to operate the gas turbine or engine
and to operate the steam turbine.
The “Tool to calculate project or leakage CO2 emissions from fossil fuel combustion” specifies that:
CO2 emissions from fossil fuel combustion in process j are calculated based on the quantity of fuels
combusted and the CO2 emission coefficient of those fuels, as follows:
yiCOEFyjFCiPE yjFC ,,,,, ∑ ∗=
where
yjFCPE ,, Are the CO2 emissions from fossil fuel combustion in process j during the year y
(tCO2/yr)
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yjFCi ,, Is the quantity of fuel type I combusted in process j during year y (mass or volume
unit/yr)
yCOEFi, Is the CO2 emission coefficient of fuel type I in yaer y (tCO2/mass or volume unit)
i Are the fuel types combusted in process j during year y
The CO2 emission coefficient COEFi,y can be calculated using one of the two options, depending on the
availability of data on the fossil fuel type i
For the proposed project activity data for option A is not available. Therefore option B is selected:
yiCOyiyi EFNCVCOEF ,,2,, *=
where
yCOEFi, Is the CO2 emission coefficient of fuel type i in year y (tCO2/mass or volume unit)
yiNCV , Is the weighted average net calorific value of the fuel type i in year y (GJ/mass or
volume unit)
yiCOEF ,,2 Is the weighted average CO2 emission factor for fuel type i in year y (tCO2/GJ)
i Are the fuel types combusted in process j during year y
Default values will be used for NCVNG,y and NCVDiesel,y.
Justification
Ex ante default values are available.
IPCCC default values for EFCO2,NG,y and EFCO2,Diesel,y are used for the ex-ante calculation of emission
reductions.
Justification:
No values provided by fuel supplier and no direct measurements by project proponent available.
Baseline emissions
The baseline scenario is the following: electricity would be generated by the operation of the power
plant in open cycle mode, and by grid-connected power plants. The baseline emissions for year y (with
assumption made regarding the baseline situation) are calculated as follows:
) - ( ,,,,,,, yXOCyCCygridyXOCOCyX EGEGEFEGEFBE ×+×= (2)
Where:
EFOC = Emission factor for plant operational in Open Cycle Mode (tCO2/MWh)
EGOC,X,y = Electricity generated by the open cycle in the baseline (MWh); as shown below,
this is calculated in two ways based on historical data (EGOC,H,y), or based on the
load factor in the project plant (EGOC,P,y) and Index X is either “H” or “P”
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EGCC,y = Actual electricity generated by project in year y (MWh)
EFgrid,y = CO2 emission factor for the electricity displaced due to the project activity during
the year y (tCO2/MWh)
If more than one fuel is used in the gas turbine or engine, the baseline calculation (equation 2) must
assume the emission factor of the least carbon intensive fuel that has been used before or after project
implementation.
Step 1: Estimating EGOC,X,y
Project participants shall estimate, by the two ways provided below, the amount of generation by the
power plant running in open cycle mode in the baseline (MWh). The calculation is done based on:
(i) The historic load situation (EGOC,H,y) and for (ii) The load situation in the project (EGOC,P,y), as
follows:
(i) Amount of baseline power generation assuming on historical data (MWh):
E ,, OCyHOC GEG = (3)
Where:
EGOC = Average net annual generation from the operation of power plant in open cycle mode
based on five years of generation records at the time of validation (MWh). If five
years data is not available, then data for the highest number of complete years
available should be used, with a minimum of three full years
For EGOC the data for the highest number of complete years is used.
Justification:
More than three but less than five years of generation records are available
(ii) And amount of baseline power generation calculated assuming load situation of project power plant
(MWh):
,,, yCC
CC
OCyPOC EG
Cap
CapEG ×= (4)
Where:
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CapOC = Net power generation capacity8 of the open cycle gas turbine or engine before the
project activity (MW)
EGCC,y = Actual electricity generated by project in year y (MWh)
CapCC = Net installed power generation capacity (MW) of the project including both the open
cycle (gas turbine or engine) and the steam turbine capacity
Step 2: Estimating EFOC, the emissions factor for electricity generated in open cycle mode in the
baseline
The emissions factor for the open cycle mode generation in the baseline (EFOC in tCO2/MWh) is given by
historical performance of the plant when it operated in open cycle using data for five years at the time of
validation. The emission factor is calculated as follows:
2 CO
OC
HISTOC EFNCV
EG
FCEF ××
= (5)
Where:
FCHIST = Annual average fuel consummation of the open cycle gas turbine or engine (mass or
volume unit) estimated using data for five years at the time of validation. If five years
data is not available, then data for the highest number of complete years available
should be used, with a minimum of three full years
EGOC = Average net annual generation from the operation of power plant in open cycle mode
(MWh)
NCV = Net calorific value of the fuel(GJ/mass or volume unit )
EFCO2 = CO2 emission factor of the fuel (tCO2/GJ)
For FCHIST the data for the highest number of complete years is used.
Justification:
More than three but less than five years of generation records are available
Step 3: Determine the emissions factor for the operating margin
The baseline emission factor (EFgrid,y) should be calculated as a combined margin (CM), following the
guidance in the “Tool to calculate the emission factor for an electricity system”.
Dispatch analysis method is not used to calculate the combined margin.
Version 2 of the “Tool to calculate the emission factor for an electricity system” is used for calculating
the combined margin.
Step 1: Identify the relevant electricity systems
The relevant electricity system is the electricity grid of the Islamic Republic of Iran.
Justification:
8 Net capacity is defined as gross capacity less auxiliary consumption of the plant.
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There are only very limited power import and exports from Iran to neighbouring countries.
Step 2: Choose whether to include off-grid power plants in the project electricity system (optional)
Option I is chosen
Justification:
Grid power plants account for the vast majority of installed capacity in Iran.
Step 3: Select a method to determine the operating margin (OM)
The calculation of the operating margin emission factor (EFgrid,OM,y) is based on one of the following
methods:
(a) Simple OM; or
(b) Simple adjusted OM; or
(c) Dispatch data analysis OM; or
(d) Average OM.
The simple OM method (option a) can only be used if low-cost/must-run resources constitute less than
50% of total grid generation in: 1) average of the five most recent years, or 2) based on long-term
averages for hydroelectricity production.
Simple OM was chosen.
Justification:
Low-cost/must-run resources constitute less than 50% of the total grid generation
Two options are available:
- Ex-ante option: the emission factor is determined once at the validation stage
- Ex post option: the emission factor is updated annually during monitoring
The ex ante option is chosen.
Justification:
3-year generation-weighted averages based on the most recent data was used.
Step 4: Calculate the operating margin emission factor according to the selected method
The project participant choose (a) Simple OM and Option B Calculation based on total fuel consumption
and electricity generation of the system.
Justification
(a) The necessary data for Option A is not available; and
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(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).
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:
Where:
EFgrid,OMsimple,y = Simple operating margin CO2 emission factor in year y (tCO2/MWh)
FCi,y = Amount of fossil fuel type i consumed in the project electricity system in year y (mass or volume
unit)
NCVi,y = Net calorific value (energy content) of fossil fuel type i in year y (GJ/mass or volume unit)
EFCO2,i,y = CO2 emission factor of fossil fuel type i in year y (tCO2/GJ)
EGy = Net electricity generated and delivered to the grid by all power sources serving the system, not
including low-cost/must-run power plants/units, in year y (MWh)
i = All fossil fuel types combusted in power sources in the project electricity system in year y
y = The relevant year as per the data vintage chosen in Step 3
Step 5: Identify the group of power units to be included in the build margin
The sample group of power units m used to calculate the build margin consists of either:
(a) The set of five power units that have been built most recently ;or
(b) The set of power capacity additions in the electricity system that comprise 20% of the system
generation (in MWh) and that have been built most recently.
Project participants should use the set of power units that comprises the larger annual generation.
The project participants used approach (b).
Justification:
Approach (b) comprises the larger annual generation in 2009.
The sample group of power units m used to calculate the build margin is based on data provided by the
Ministery of Electricity and Renewable Energy. The Power plants registered as CDM project activities
were excluded from the sample group m.
Two options for data vintages are available:
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- Option 1: calculation ex ante based on the most recent information available
- Option 2: annual updating based on the latest available information
Option 1: ex ante calculation was chosen
Step 6: Calculate the build margin emission factor
The build margin emissions factor is the generation-weighted average emission factor (tCO2/MWh) of
all power units m during the most recent year y for which power generation data is available, calculated
as follows:
Where:
EFgrid,BM,y = Build margin CO2 emission factor in year y (tCO2/MWh)
EGm,y = Net quantity of electricity generated and delivered to the grid by power unit m in year y (MWh)
EFEL,m,y = CO2 emission factor of power unit m in year y (tCO2/MWh)
m = Power units included in the build margin
y = Most recent historical year for which power generation data is available
Step 7: Calculate the combined margin emissions factor
The combined margin emissions factor is calculated as follows
EFgrid,CM,y=EFgrid,OM,y x wom+EFgrid,BM,y x wBM
Where:
EFgrid,BM,y = Build margin CO2 emission factor in year y (tCO2/MWh)
EFgrid,OM,y = Operating margin CO2 emission factor in year y (tCO2/MWh)
wOM = Weighting of operating margin emissions factor (%)
wBM = Weighting of build margin emissions factor (%)
Since the proposed project activity is no wind or solar power generation project, the default values wOM =
0.5 and wBM = 0.5 are used for the first crediting period.
Step 4: Conservatively determine baseline emissions
The baseline emission BEy for year y is the lower value between the baseline emissions calculated on the
basis of historical power generation, BEH,y, and the baseline emissions calculated based on the load
factor of the project situation, BEP,y:
),( ,, yPyHy BEBEMINBE = (6)
∑
∑ ×
=
m
ym
ymEL
m
ym
yBMgridEG
EFEG
EF,
,,,
,,
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Where BEH,y, and BEP,y are determined with equations (2) to (5).
Leakage
The main emissions potentially giving rise to leakage in the context of the proposed projects are:
(i) CH4 leakage in production, transportation and consumption of increased quantity of
natural gas consumed by the project activity; and
(ii) Emissions arising due to power plant construction.
The CH4 emissions can be ignored while applying this methodology, if project proponents demonstrate
through estimation that these are a negligible fraction of baseline.
Overall the project activity will decrease the volume of gas consumed per unit of electricity produced in
Iran. It should therefore have positive leakage affects on fugitive emissions of gas, especially since the
baseline scenario to meet increasing electricity demand is to build further open cycle gas fired power
plants. However such positive leakage is not considered by the methodology ACM007 v4. But this
clearly demonstrates that emissions due to leakage through upstream fugitive emissions are a negligible
fraction of baseline emissions, and will be ignored.
Project participants do not need to consider construction related emission sources as leakage in
applying this methodology. Project activities using this baseline methodology shall not claim any credit
for the project on account of reducing these emissions below the level of the baseline scenario.
No credits for the reduction of construction related emissions are claimed.
B.6.2. Data and parameters that are available at validation:
Data / Parameter: EGOC
Data unit: MWh
Description: Historical net quantity of electricity generated by the Open Cycle operation of
power plant
Source of data
used:
Generation records. Historical data of electricity supplied by the project to the
grid, preferably for five year should be used and not less than three years
Value applied: 1,685,221
Justification of the
choice of data
Official published data by Tavanir.
Year Output (MWh)
21/3/2007-20/3/2008 1,046,254
21/3/2008-20/3/2009 2,119,721
21/3/2009-20/3/2010 1,889,688
Average 1,685,221
Any comment: Official data published by Tavanir based on direct measurements by plant
operator.
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Data / Parameter: CapOC
Data unit: MW
Description: Net power generation capacity9 of the open cycle gas turbine or engine (before the
project activity)
Source of data
used:
Manufacturer’s specification
Value applied: 634.668
Justification of the
choice of data
Manufacturer’s specification
Any comment:
Data / Parameter: CapCC
Data unit: MW
Description: Net generation capacity of the project power plant
Source of data
used:
Manufacturer’s specification
Value applied: 942.268
Justification of the
choice of data
Manufacturer’s specification
Any comment:
Data / Parameter: FCHIST Nat Gas
Data unit: Nm3
Description: Historic natural gas consumption of the project in Open cycle generation
Source of data
used:
Historical data of annual fuel consumption by the project operating in open cycle
mode
Value applied: 457,850,333
Justification of the
choice of data
Official data published by Tavanir.
Year Natural gas (Nm3)
21/3/2007-20/3/2008 234,419,000
21/3/2008-20/3/2009 608,230,000
21/3/2009-20/3/2010 530,902,000
Average 457,850,333
Any comment: Official data published by Tavanir based on direct measurements by plant
operator.
Data / Parameter: FCHIST, Diesel
Data unit: lit
Description: Historic diesel consumption of the project in Open cycle generation
Source of data
used:
Historical data of annual fuel consumption by the project operating in open cycle
mode
Value applied: 60,191,000
Justification of the Official data published by Tavanir
9 Net capacity is defined as gross capacity less auxiliary consumption of the plant.
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choice of data Year Diesel (lit)
21/3/2007-20/3/2008 97,260,000
21/3/2008-20/3/2009 41,307,000
21/3/2009-20/3/2010 42,006,000
Average 60,191,000
Any comment: Official data published by Tavanir based on direct measurements by plant
operator.
Data / Parameter: NCVNG
Data unit: GJ / Nm3
Description: Net calorific value of natural gas used previous to the start of project
Source of data
used:
Default values
Value applied: 0.03855
Justification of the
choice of data
Fuel supplier does not provide fuel values on invoice
Any comment:
Data / Parameter: NCVDiesel
Data unit: GJ/lit
Description: Net calorific value of diesel used previous to the start of project
Source of data
used:
Default values
Value applied: 0.03803
Justification of the
choice of data
Fuel supplier does not provide fuel values on invoice
Any comment:
Data / Parameter: EFCO2
Data unit: tCO2/GJ
Description: CO2 emission factor for fossil fuel used previous to the start of project
Source of data
used:
IPCC default values at the upper limit of the uncertainty at a 95% confidence
interval as provided in table 1.4 of Chapter1 of Vol. 2 (Energy) of the 2006 IPCC
Guidelines on National GHG Inventories
Value applied: 0.0583
Justification of the
choice of data
The following alternatives are not available:
- Values provided by the fuel supplier
- Measurements by the project participant
- Regional or national default values
The value for diesel oil is 0.0748. In line with the requirements of the
methodology the emission factor of the least carbon intensive fuel that has been
used before or after project implementation is used (ie. the value for natural gas)
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Any comment:
B.6.3. Ex-ante calculation of emission reductions:
Baseline emissions
Baseline emissions are calculated by multiplying the electricity generated in the open cycle mode with
the grid emission factor of the power plant in the open cycle mode plus multiplying the additional
electricity produced by the power plant in combined cycle mode with the grid emission factor.
) - ( ,,,,,,, yXOCyCCygridyXOCOCyX EGEGEFEGEFBE ×+×= (7)
Step 1: Estimating EGOC,X,y
Two ways exist to estimate the amount of power generated in the baseline:
(i) Amount of baseline power generation assuming on historical data (MWh):
E ,, OCyHOC GEG =
Data for the last three years of electricity production is available:
Year Output (MWh)
21/3/2007-20/3/2008 1,046,254
21/3/2008-20/3/2009 2,119,721
21/3/2009-20/3/2010 1,889,688
Average 1,685,221
Therefore EGOC = 1,685,221 MWh (8)
(ii) And amount of baseline power generation calculated assuming load situation of project power plant
(MWh):
,,, yCC
CC
OCyPOC EG
Cap
CapEG ×= (9)
The yearly electricity generated by the project activity is estimated according to the following formula:
EGCC,y=CapCC*OperatingHoursCC*AuxConsCC*(DegCC^y)
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Where :
- OperatingHoursCC are the expected operating hours of the project activity
- AuxConsCC is the expected auxiliary consumption of the project activity
- DegCC is the expected degradation of the project activity
The calculation is based on the following assumptions
Variable Value Unit
CapOC 560 MW (site condition)
Degradation (DegCC) 0.4% %
OperatingHoursCC 3,168 h
Auxiliary consumption
(AuxConsCC) 1.2% %
CapCC 840 MW (site condition)
This yields the following results:
Year EGCC,y EGOC,P,y
1 2,618,429 1,745,619
2 2,607,955 1,738,637
3 2,597,523 1,731,682
4 2,587,133 1,724,756
5 2,576,785 1,717,857
6 2,566,478 1,710,985
7 2,556,212 1,704,141
8 2,545,987 1,697,325
9 2,535,803 1,690,535
10 2,525,660 1,683,773
Step 2: Estimating EFOC, the emissions factor for electricity generated in open cycle mode in the
baseline
2 CO
OC
HISTOC EFNCV
EG
FCEF ××
= (10)
The annual fuel consumption over the last three years was the following:
Year
Fuel consumption
Diesel (l) Natural gas (Nm3)
21/3/2007-20/3/2008 97,260,000 234,419,000
21/3/2008-20/3/2009 41,307,000 608,230,000
21/3/2009-20/3/2010 42,006,000 530,902,000
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Average (FCHIST) 60,191,000 457,850,333
EGOC = 1,685,221 MWh
The net calorific values for diesel and natural gas:
NCVNG,y = 0.03855 GJ/Nm3
NCVDiesel,y = 0.03803 GJ/lit
The calculation yields an emission factor EFOC = 0.690
Step 3: Determine the emissions factor for the operating margin
a) Calculate the operating margin
EFgrid,OM-simple,2007 EFgrid,OM-simple,2008 EFgrid,OM-simple,2009
[ton CO2/MWh] [ton CO2/MWh] [ton CO2/MWh]
A B C
0.66730 0.66619 0.66772
Total EGm,2007
(excluding low-
cost must run
and Imports)
Weight 2007 Total EGm,2008
(excluding low-cost
must run and
Imports)
Weight 2008 Total EGm,2009
(excluding low-cost
must run and Imports)
Weight 2009
[MWh] [MWh] [MWh]
D E=D/J F G=F/J H I=H//J
178,060,000 0.3046 201,037,000 0.3439 205,475,000 0.3515
Total EGm2007-2009
(excluding low-cost
must run and Imports)
EFgrid,OM-simple, 2007-2009
3 year generation weighted
average
[MWh] [ton CO2/MWh]
J=D+F+H K=A*E+B*G+C*I
584,572,000 0.6671
b) Calculate the build margin emission factor
∑
∑ ×
=
m
ym
ymEL
m
ym
yBMgridEG
EFEG
EF,
,,,
,,
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Where = 28,338,129.27 tCO2e
= 44,875,346 MWh
= 0.6315 tCO2e/MWh
c) Calculate the combined margin emissions factor
EFgrid,CM,y=EFgrid,OM,y x wom+EFgrid,BM,y x wBM
Step 4: Conservatively determine baseline emissions
),( ,, yPyHy BEBEMINBE = (11)
Calculating BEH,y
Year EFOC EGOC,H,y EFGrid EGCC,y BEH,y,
1 0.690 1,685,221 0.649 2,618,429 1,768,365
2 0.690 1,685,221 0.649 2,607,955 1,761,564
3 0.690 1,685,221 0.649 2,597,523 1,754,791
4 0.690 1,685,221 0.649 2,587,133 1,748,045
5 0.690 1,685,221 0.649 2,576,785 1,741,326
6 0.690 1,685,221 0.649 2,566,478 1,734,634
7 0.690 1,685,221 0.649 2,556,212 1,727,969
8 0.690 1,685,221 0.649 2,545,987 1,721,330
9 0.690 1,685,221 0.649 2,535,803 1,714,718
10 0.690 1,685,221 0.649 2,525,660 1,708,132
Calculating BEPy
EFgrid,OM-simple 2007-2009 wOM EFgrid,BM,2009 wBM EFgrid,CM,2007-2009
[ton CO2/MWh] - [tCO2/MWh] - [tCO2/MWh]
0.67 0.50 0.63 0.50 0.65
) - ( ,,,,,,, yHOCyCCygridyHOCOCyH EGEGEFEGEFBE ×+×=
ymEL
m
ym EFEG ,,, ×∑
∑m
ymEG ,
yBMgridEF ,,
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Year EFOC EGOC,P,y EFGrid EGCC,y BEP,y,
1 0.690 1,745,619 0.649 2,618,429 1,770,812
2 0.690 1,738,637 0.649 2,607,955 1,763,729
3 0.690 1,731,682 0.649 2,597,523 1,756,674
4 0.690 1,724,756 0.649 2,587,133 1,749,647
5 0.690 1,717,857 0.649 2,576,785 1,742,648
6 0.690 1,710,985 0.649 2,566,478 1,735,678
7 0.690 1,704,141 0.649 2,556,212 1,728,735
8 0.690 1,697,325 0.649 2,545,987 1,721,820
9 0.690 1,690,535 0.649 2,535,803 1,714,933
10 0.690 1,683,773 0.649 2,525,660 1,708,073
Based on the above calculations BEH,y is lower and hence BEy = BEH,y
Project emissions
Project emissions are calculated based on the “Tool to calculate project or leakage CO2 emissions from
fossil fuel combustion”, Version 02
Where we choose option B to calculate COEFi,y :
The relative energy input of diesel and natural gas is calculated based on their historic consumption:
Diesel Natural gas
Average consumption 60,191,000 457,850,333
NCV 0.03803 0.03855
Energy input 2,289,064 17,650,130
Energy input in % 0.115 0.885
The energy input is estimated using the nameplate efficiency of the project activity (51%), and calculated
separately for diesel and natural gas:
Year EGCC,y EfficiencyCC Energy Input (MWh) Energy Input (GJ)
Energy input
Diesel (GJ)
Energy input
Natural Gas (GJ)
1 2,618,429 51% 5,134,174 18,483,028 2,121,893 16,361,135
2 2,607,955 51% 5,113,638 18,409,096 2,113,405 16,295,691
3 2,597,523 51% 5,093,183 18,335,460 2,104,951 16,230,508
4 2,587,133 51% 5,072,810 18,262,118 2,096,532 16,165,586
yiCOEFyjFCiPE yjFC ,,,,, ∑ ∗=
yiCOyiyi EFNCVCOEF ,,2,, *=
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5 2,576,785 51% 5,052,519 18,189,069 2,088,146 16,100,924
6 2,566,478 51% 5,032,309 18,116,313 2,079,793 16,036,520
7 2,556,212 51% 5,012,180 18,043,848 2,071,474 15,972,374
8 2,545,987 51% 4,992,131 17,971,672 2,063,188 15,908,485
9 2,535,803 51% 4,972,163 17,899,786 2,054,935 15,844,851
10 2,525,660 51% 4,952,274 17,828,187 2,046,715 15,781,471
Based on this, the project emissions are calculated:
Year
Energy input
Diesel (GJ) EFCO2, Diesel
Energy input Natural
Gas (GJ) EFCO2, Nat Gas PEy
1 2,121,893 0.0748 16,361,135 0.0583 1,112,572
2 2,113,405 0.0748 16,295,691 0.0583 1,108,121
3 2,104,951 0.0748 16,230,508 0.0583 1,103,689
4 2,096,532 0.0748 16,165,586 0.0583 1,099,274
5 2,088,146 0.0748 16,100,924 0.0583 1,094,877
6 2,079,793 0.0748 16,036,520 0.0583 1,090,498
7 2,071,474 0.0748 15,972,374 0.0583 1,086,136
8 2,063,188 0.0748 15,908,485 0.0583 1,081,791
9 2,054,935 0.0748 15,844,851 0.0583 1,077,464
10 2,046,715 0.0748 15,781,471 0.0583 1,073,154
No leakage is assumed, hence LEy=0
Overall, this leads to the following emission reduction calculations:
Years BEy Pey LEy ERy
1 1,768,365 1,112,572 0 655,793
2 1,761,564 1,108,121 0 653,443
3 1,754,791 1,103,689 0 651,102
4 1,748,045 1,099,274 0 648,771
5 1,741,326 1,094,877 0 646,449
6 1,734,634 1,090,498 0 644,136
7 1,727,969 1,086,136 0 641,833
8 1,721,330 1,081,791 0 639,539
9 1,714,718 1,077,464 0 637,254
10 1,708,073 1,073,154 0 634,919
B.6.4 Summary of the ex-ante estimation of emission reductions:
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Year Estimation of project
activity Emissions
(tonnes of CO2 e)
Estimation of baseline
emissions (tonnes of
CO2 e)
Estimation of
leakage
(tonnes of CO2
e)
Estimation of
overall emission
reductions (tonnes
of CO2 e)
1 1,112,572 1,768,365 0 655,793
2 1,108,121 1,761,564 0 653,443
3 1,103,689 1,754,791 0 651,102
4 1,099,274 1,748,045 0 648,771
5 1,094,877 1,741,326 0 646,449
6 1,090,498 1,734,634 0 644,136
7 1,086,136 1,727,969 0 641,833
8 1,081,791 1,721,330 0 639,539
9 1,077,464 1,714,718 0 637,254
10 1,073,154 1,708,073 0 634,919
Total tonnes
of CO2e 17,380,815 10,927,576 0 6,453,239
B.7. Application of the monitoring methodology and description of the monitoring plan:
B.7.1 Data and parameters monitored:
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Data / Parameter: EGCC,y
Data unit: MWh
Description: Net quantity of electricity generated by the project power plant in year y
Source of data to be
used:
Measurements by the project participant
Value of data applied
for the purpose of
calculating expected
emission reductions in
section B.6
Year EGCC,y
1 2,618,429
2 2,607,955
3 2,597,523
4 2,587,133
5 2,576,785
6 2,566,478
7 2,556,212
8 2,545,987
9 2,535,803
10 2,525,660
Description of
measurement methods
and procedures to be
applied:
The net generated electricity is calculated through direct measurements of the
electricity generated by the power plant (gross quantity) and the electricity
consumed by the power plant (auxiliary consumption) by Landis and Gyr 3
phase 4 wire electricity meter.
The readings of the electricity meters will be read every month by the Data
Recorder.
Monitoring frequency: Continuously
QA/QC procedures to
be applied:
The consistency of metered net electricity generation will be cross-checked with
receipts from sales (if available). Meters will be subject to regular maintenance
and testing regime to ensure efficiency in order with manufacturer
specifications, which is equal to a calibration every 10 years. The accuracy of
the meter is equal to 0.2%.
Any comment: The data shall be archived for 2 years following the end of the crediting period.
Data / Parameter: FCNG,y (Natural Gas)
Data unit: m3/yr
Description: Quantity of fuel type Natural Gas combusted during the year y
Source of data to be
used:
Onsite measurements by the project participant
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Value of data applied
for the purpose of
calculating expected
emission reductions in
section B.6
Year
Natural gas (Nm3)
21/3/2007-20/3/2008 234,419,000
21/3/2008-20/3/2009 608,230,000
21/3/2009-20/3/2010 530,902,000
Average 457,850,333
Description of
measurement methods
and procedures to be
applied:
The consumption of natural gas is measured by a turbine gas flow meter. The
flow meter will be read monthly by the Data Recorder..
Monitoring frequency Continuously
QA/QC procedures to
be applied:
The period of calibration is in line with manufacturer’s specifications, but will
be at least every 10 years.
The consistency of metered fuel consumption quantities will be crosschecked by
an annual energy balance that is based on purchased quantities and stock
changes.
The metered gas consumption quantities will also be crosschecked with available
purchase invoices from financial records.
Any comment: The data shall be archived for 2 years following the end of the crediting period.
Data / Parameter: FCDiesel,y (Diesel Oil)
Data unit: lit/yr
Description: Quantity of fuel type Diesel Oil combusted during the year y
Source of data to be
used:
Onsite measurements by the project participant
Value of data applied
for the purpose of
calculating expected
emission reductions in
section B.6
Year Diesel (lit)
21/3/2007-20/3/2008 97,260,000
21/3/2008-20/3/2009 41,307,000
21/3/2009-20/3/2010 42,006,000
Average 60,191,000
Description of
measurement methods
and procedures to be
applied:
The consumption of diesel is measured by a turbine oil flow meter. The flow
meter will be read monthly by the Data Recorder.
Monitoring frequency Continuously
QA/QC procedures to
be applied:
The period of calibration is in line with manufacturer’s specifications, but will
be at least 10 years.
The consistency of metered fuel consumption quantities will be crosschecked by
an annual energy balance that is based on purchased quantities and stock
changes.
The metered fuel consumption quantities will also be crosschecked with
available purchase invoices from financial records.
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Any comment: The data shall be archived for 2 years following the end of the crediting period.
Data / Parameter: NCVNG,y (Natural Gas)
Data unit: GJ/m3
Description: Net calorific of fuel type Natural Gas in year y
Source of data to be
used:
One of the following data sources will be used, depending on their availability:
Data source Conditions for using the data source
(a) Values provided by the fuel
supplier in invoices
This is the preferred source
(b) Measurements by the project
participants
If (a) is not available
(c) IPCC default values at the upper
limit of the uncertainty at a 95%
confidence interval as provided
in table 1.4 of Chapter1 of Vol. 2
(Energy) of the 2006 IPCC
Guidelines on National GHG
Inventories
If (a) is not available
Value of data applied
for the purpose of
calculating expected
emission reductions
in section B.6
0.03855
Description of
measurement methods
and procedures to be
applied:
Measurements will be undertaken in line with national or international fuel
standards
Monitoring frequency For a) and b): The NCV will be obtained for each fuel delivery, from which
weighted average annual values will be calculated
For c): Any future revision of the IPCC Guidelines should be taken into account
QA/QC procedures to
be applied:
Values will be verified if they are within the uncertainty range of the IPCC default
values as provided in Table 1.2, Vol. 2 of the 2006 IPCC Guidelines. If the values
fall below this range additional information from the testing laboratory shall be
collected to justify the outcome or additional measurements shall be conducted.
The testing laboratory should have ISO17025 accreditation or justify that they can
comply with similar quality standards
Any comment: The data shall be archived for 2 years following the end of the crediting period.
Data / Parameter: NCVDiesel,y (Diesel Oil)
Data unit: GJ/lit
Description: Net calorific of fuel type Diesel Oil in year y
Source of data to be
used:
One of the following data sources will be used, depending on their availability:
Data source Conditions for using the data source
(a) Values provided by the fuel
supplier in invoices
This is the preferred source
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(b) Measurements by the project
participants
If (a) is not available
(c) Regional or national default
values
If (a) is not available
These sources will be based on well-
documented, reliable sources (such as
national energy balances)
(d) IPCC default values at the upper
limit of the uncertainty at a 95%
confidence interval as provided
in table 1.4 of Chapter1 of Vol. 2
(Energy) of the 2006 IPCC
Guidelines on National GHG
Inventories
If (a) is not available
Value of data applied
for the purpose of
calculating expected
emission reductions
in section B.6
0.03803
Description of
measurement methods
and procedures to be
applied:
Measurements will be undertaken in line with national or international fuel
standards
Monitoring frequency For a) and b): The NCV will be obtained for each fuel delivery, from which
weighted average annual values will be calculated
For c), the appropriateness of the values will be reviewed annually
For d): Any future revision of the IPCC Guidelines should be taken into account
QA/QC procedures to
be applied:
Values will be verified if they are within the uncertainty range of the IPCC default
values as provided in Table 1.2, Vol. 2 of the 2006 IPCC Guidelines. If the values
fall below this range additional information from the testing laboratory shall be
collected to justify the outcome or additional measurements shall be conducted.
The testing laboratory should have ISO17025 accreditation or justify that they can
comply with similar quality standards
Any comment: The data shall be archived for 2 years following the end of the crediting period.
Data / Parameter: EFCO2NG,y
Data unit: tCO2/GJ
Description: Emission factor of fuel type Natural Gas in year y
Source of data to be
used:
One of the following data sources will be used, depending on their availability:
Data source Conditions for using the data source
(a) Values provided by the fuel
supplier in invoices
This is the preferred source
(b) Measurements by the project
participants
If (a) is not available
(c) IPCC default values at the upper If (a) is not available
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limit of the uncertainty at a 95%
confidence interval as provided
in table 1.4 of Chapter1 of Vol. 2
(Energy) of the 2006 IPCC
Guidelines on National GHG
Inventories
Value of data applied
for the purpose of
calculating expected
emission reductions
in section B.6
0.0583
Description of
measurement methods
and procedures to be
applied:
Measurements will be undertaken in line with national or international fuel
standards.
Monitoring frequency For a) and b): The CO2 emission factor will be obtained for each fuel delivery,
from which weighted average annual values will be calculated
For c): Any future revision of the IPCC Guidelines will be taken into account
QA/QC procedures to
be applied:
Any future revision of the IPCC Guidelines should be taken into account
Any comment: The data shall be archived for 2 years following the end of the crediting period.
B.7.2. Description of the monitoring plan:
Responsibilities for monitoring
At the plant a CDM Manager will be trained to supervise the collection, aggregation and storage of the
required data from the regular monitoring activities, as well as the calibration and maintenance of the
measurement equipments. The Data Recorders and Meter Supervisors will take charge of the regular
monitoring tasks, and will provide the relevant data to the CDM Manager.
All staff involved in any of the procedures related with the CDM project activity will be trained in order
to perform the tasks specified in the monitoring plan by the CDM consultant.
Operational Management
The detailed calibration, testing and maintenance procedure for the measurement equipments used to
monitor data of the project activity shall be prepared by the CDM Manager based on the agreements with
equipment manufacturer’s recommendations and the industry and national standards as applicable.
Meters will be installed, maintained and calibrated according to equipment manufacturer instructions and
be in line with national standards, or, if these are not available, international standards (e.g. IEC, ISO).
The data collected as part of monitoring will, whenever possible, be archived electronically and be kept
at least for 2 years after the end of the last crediting period. Records used for monitoring which are not
available in electronic format will be stored physically. The records for calibration, testing and
maintenance of meters will be also readily accessible for the DOE during verification
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All electronic data will be remotely monitored and recorded from the power plant control centre. Staff
working at the control centre will prepare a report on the operations of the CDM project activity and this
report will record data readings and equipment defects, outages, repairs and maintenance activities. All
relevant information, notes of meetings, data files, maintenance records, defect reports, hard copy and
computerized records of monitoring will be kept at the control centre or other designated location, and
arranged in an orderly and transparent manner to facilitate audit as and when required.
Operation and Management structure:
Group members and their responsibilities
Person Responsibility
Power plant manager Supervises the implementation of monitoring plan
CDM Manager Managing the whole CDM data processing for Shirvan power plant,
guiding and supervising data recorder after training by CDM consultant.
CDM consultant Providing CDM Manager training and technical support about CDM
monitoring plan.
Data recorder Collecting and recording data every month.
Meter supervisor Checking power meter periodically according to relevant regulation.
Emergency preparedness
Disposal of Emergency will be implemented according to the stipulations in the regulations of the
Shirvan Power Plant.
Annex 4 contains further background information.
B.8. Date of completion of the application of the baseline study and monitoring methodology
Power plant manager
CDM Manager
Meter supervisor Data recorder
CDM consultant
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and the name of the responsible person(s)/entity(ies):
10/04/2011
Roman Schibli
Swiss Carbon Assets Ltd. (Project Participant)
www.southpolecarbon.com
SECTION C. Duration of the project activity / crediting period
C.1. Duration of the project activity:
C.1.1. Starting date of the project activity:
01/10/2007, first payment by IPDC to MAPNA for the proposed project activity.
C.1.2. Expected operational lifetime of the project activity:
20 years, 0 months
C.2. Choice of the crediting period and related information:
Fixed crediting period.
C.2.1. Renewable crediting period:
C.2.1.1. Starting date of the first crediting period:
Not applicable
C.2.1.2. Length of the first crediting period:
Not applicable
C.2.2. Fixed crediting period:
C.2.2.1. Starting date:
01/05/2011 or date of registration, whichever is later
C.2.2.2. Length:
10 years, 0 months
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SECTION D. Environmental impacts
D.1. Documentation on the analysis of the environmental impacts, including transboundary
impacts:
Ghods Niroo carried out an Environmental Impact Assessment of the Shirvan Power Plant.
Section D.2 summarizes the main potential environmental impacts, recommended actions and monitoring
responsibilities.
D.2. If environmental impacts are considered significant by the project participants or the host
Party, please provide conclusions and all references to support documentation of an environmental
impact assessment undertaken in accordance with the procedures as required by the host Party:
Remarks Monitoring Agent Frequency of
monitoring
Monitoring
requirement
Recommended
action
Potential
Environmental
Impacts/issues
Main pollutant
parameters as are:
SOx ,NOx , HC ,
COx ,TSPM, H2S
Reliable Private Lab
Consulting
Companies
Approved by DOE
According to
EMS Plan( Stack
Sampling &
Monitoring
program)
Stack Emission
Standards
provided by
DOE10 of Iran
Should be
followed
Concentration of
air pollutant
parameters be
monitored
Emission of
Power plant main
stacks
HSE11 after
commencement
of operation :the
once every
months
Emission of any
ducts����
Main pollutant
parameters as are:
SO2 ,NO2 , HC ,
CO , PM10 , H2S
Reliable Private Lab
Consulting
Companies
Approved by DOE
According to
EMS Plan (air
quality Sampling
or Monitoring
program)
Clean air
Standards
provided by DOE
of Iran should be
followed
Ambient air
quality be
monitored Ambient Air
Different pollutant
parameters such as:
PM10, Mist , Fumes
& etc.
Reliable Private Lab
Consulting
Companies
Approved by MOH
Initially 3months
after
commencement
of operation,
then once every
6months
Indoor air
Standards
provided by
MOH12 of Iran
Should be
followed
Indoor air quality
be monitored
Indoor Air
COx NOx HC Reliable Private Lab
Consulting
Companies
Approved by DOE
Quarterly Testing Passenger
&Trucks
Vehicles
emission
Standards
provided by
DOE of Iran
Should be
followed
Motor Vehicles
Exhaust Gas be
tested
Mobile Sources
LEQ at Daily & Reliable Private Lab According to Sound Level LEQ of Noise Out door Sound
10 Provincial Department of Environment = DOE
11 Department of power plant Health Safety Environment = HSE
12 Ministry of Health = MoH
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Night Hours Consulting
Companies
Approved by DOE
EMS Plan (Noise
pollution Testing
or Monitoring
program
Standards
provided by
DOE of Iran
Should be
followed
pollution be
monitored
Level
SPL & LEQ Reliable Private Lab
Consulting
Approved by MOH
after
commencement
of operation :the
once every
months
Sound Level
Standards
provided by
MOH of Iran
Should be
followed
SPL & LEQ of
Noise pollution be
monitored In door Sound
Level
pH,BOD 5 ,COD,
TSS, TDS,ABS,
Total & Fecal
Coliforms, Oil &
Grease
Reliable Private Lab
Consulting
Approved by DOE
once every
months
Waste Water
discharge
Standards
provided by DOE
of Iran Should be
followed
Water Quality
parameters &
Level of oil &
grease in water be
monitored
Water Discharge
Reliable Private
Execution
Companies
Approved by
MOM°
every day Appropriate
positioning of
waste bins
Disposal off at the
waste disposal site
by Malayer
district Solid Waste
Reliable Private
Execution
Companies
Approved by DOE
or MOM°
Continuously Appropriate
positioning of
Hazardous waste
bins & Chambers
Disposal at the
hazardous waste
disposal site
Approved by DOE Industrial Waste
SECTION E. Stakeholders’ comments
E.1. Brief description how comments by local stakeholders have been invited and compiled:
To collect feedback from local stakeholders on the proposed project activity, the project participants
organized a public meeting on April 10 2011 (21.01.1390 in the Persian calendar). The meeting was
announced on April 6 2011 (17.01.1390) in a local newspaper. Direct invitations to key stakeholders were also sent. 35 stakeholders including workers at the power plant, members of neighboring
communities and authorities took part in the meeting. The meeting lasted for 1.5 hours. It was started
with a presentation on the proposed project activity and its benefits. Then background information on the
CDM and climate change were given. Finally there stakeholders were invited to comment directly on the
project. Stakeholder feedback was received verbally, and are compiled in the minutes of the meeting.
E.2. Summary of the comments received:
During the discussions, the following points were raised:
- Mr. Mousavi who works for the local administration asked, whether the CDM could also be used
to finance the conversion of the third block of the power plant to combined cycle, which is
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currently not included in the project activity. The presenter explained that this option was being
evaluated.
- Ms Naghdi asked whether the fact that the project was going to benefit from the CDM was going
to increase local employment. No such concrete plans exist, but the presenter found this an
interesting suggestion. Other participants strongly supported this suggestion.
- Mr Jamshidi, a local resident expressed his wish that Shirvan was going to be the first CDM
project in Iran, to demonstrate the local commitment to preserving the environment.
- Multiple questions concerning the CDM were answered, and several new project ideas (landfill,
energy efficiency) were brought up.
In a final poll on the project, all present stakeholders expressed their strong support for the proposed
project activity.
E.3. Report on how due account was taken of any comments received:
The stakeholders attending the local stakeholder consultation meeting were all very supportive to the
proposed project. There were no objections received. The project participant will put proper measures
into effect as described in the EIA during construction and operation to minimize the negative impacts on
the environment.
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Annex 1
CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY
Organization: Iran Power Development Company
Street/P.O.Box: Shahid Sahamati St, Vali-e-asr Ave
Building: 3
City: Tehran
State/Region: Tehran
Postcode/ZIP:
Country: Iran
Telephone: +98 021 - 88 80 45 04
FAX:
E-Mail:
URL: http://www.ipdc.ir/
Represented by:
Title:
Salutation: Mrs
Last name: Buzari
Middle name:
First name: Mitra
Department:
Mobile:
Direct FAX:
Direct tel: +98 021 - 88 80 45 04
Personal e-mail:
Organization: Energy Changes Projektentwicklung GmbH
Street/P.O.Box: Obere Donaustrasse
Building: 12/28
City: Vienna
State/Region:
Postcode/ZIP: 1020
Country: Austria
Telephone: +43 1 9684529
FAX: +43 1 9684529
E-Mail: [email protected]
URL: www.energy-changes.com
Represented by: Clemens Plöchl
Title: Managing Partner
Salutation: Mr.
Last name: Plöchl
Middle name:
First name: Clemens
Department:
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Mobile:
Direct FAX: +43 1 9684529
Direct tel: +43 1 9684529
Personal e-mail: [email protected]
Organization: Swiss Carbon Assets Ltd.
Street/P.O.Box: Technoparkstrasse
Building: 1
City: Zurich
State/Region: Zurich
Postcode/ZIP: 8005
Country: Switzerland
Telephone: +41 43 501 35 50
FAX: +41 43 501 35 99
E-Mail: [email protected]
URL: www.southpolecarbon.com
Represented by: Renat Heuberger
Title: Managing Partner, CEO
Salutation: Mr.
Last name: Heuberger
Middle name:
First name: Renat
Department:
Mobile:
Direct FAX: +41 43 501 35 99
Direct tel: +41 43 501 35 50
Personal e-mail: [email protected]
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Annex 2
INFORMATION REGARDING PUBLIC FUNDING
There is no public funding for the project activity.
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Annex 3
BASELINE INFORMATION
Synchronization dates of gas turbines:
Number of power unit Number of gas turbine Synchronization date End-date of lifetime
of gas turbine
Block 1 Gas turbine 1 16.03.2006 16.03.2031
Gas turbine 2 10.05.2006 10.05.2031
Block 2 Gas turbine 3 05.07.2006 05.07.2031
Gas turbine 4 06.09.2006 06.09.2031
Source: Iran Power Development Company
Historic electricity production and fuel consumption data, Shirvan Power Plant:
gasoil
(liter)
gas
(cubic
meter)
crude oil
21/3/2005-20/3/2006
21/3/2006-20/3/2007 126895 5033 121862 42989 - 1669
21/3/2007-20/3/2008 228012 4774 223238 19628 52709 - 2272
21/3/2008-20/3/2009 483788 11018 472770 10415 136969 - 4849
21/3/2009-20/3/2010 539077 17577 521500 15270 146080 - 5363
21/3/2005-20/3/2006
21/3/2006-20/3/2007 104210 2507 101703 35366 - 1782
21/3/2007-20/3/2008 259086 3115 255971 26494 54496 - 2442
21/3/2008-20/3/2009 683902 10357 673545 14431 191253 - 6747
21/3/2009-20/3/2010 566736 1892 564844 8711 159180 - 5618
21/3/2005-20/3/2006
21/3/2006-20/3/2007 48607 1348 47259 16983 - 1540
21/3/2007-20/3/2008 273431 3962 269469 19921 65246 - 2535
21/3/2008-20/3/2009 485284 3022 482262 8650 138463 - 4901
21/3/2009-20/3/2010 346662 2747 343915 8818 96699 - 3511
21/3/2005-20/3/2006
21/3/2006-20/3/2007 51201 1162 50039 16394 - 524
21/3/2007-20/3/2008 302865 5289 297576 31217 61968 - 2711
21/3/2008-20/3/2009 494527 3383 491144 7811 141545 - 4949
21/3/2009-20/3/2010 462328 2899 459429 9207 128943 - 4664
21/3/2005-20/3/2006 0 0 0 0 0 - 0
21/3/2006-20/3/2007 330913 10050 320863 111732 0 - 524
21/3/2007-20/3/2008 1063394 17140 1046254 97260 234419 - 2272
21/3/2008-20/3/2009 2147501 27780 2119721 41307 608230 - 4849
21/3/2009-20/3/2010 1914803 25115 1889688 42006 530902 - 3511
unit year
gross
output
power
(MWh)
05.07.2006
06.09.2006
1
2
3
4
Total
annual
operatio
n hours
16.03.2006
10.05.2006
internal
consump
tion
(MWh)
consuming fuel (thousands)Commissi
oning date
unit
output
(MWh)
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Source: official data by Tavanir
http://www.tavanir.org.ir/info/stat88/tafsili/tolid/chapter2/vahed%20be%20vahed/main.htm
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Annex 4
MONITORING INFORMATION
A. Operation and Management structure:
Group members and their responsibilities
Person Responsibility
Power plant manager Supervises the implementation of monitoring plan
CDM Manager Managing the whole CDM data processing for Shirvan power plant,
guiding and supervising data recorder after training by CDM consultant.
CDM consultant Providing CDM Manager training and technical support about CDM
monitoring plan.
Data recorder Collecting and recording data every month.
Meter supervisor Checking power meter periodically according to relevant regulation.
B. Monitoring procedure
The steps of monitoring the electricity supplied to the grid and the fuel supplied to the power plant are as
follows:
(1) The electricity supplied by the project to the grid will be automatically monitored. The data is
measured continuously.
(2) Persons in charge of data record and meter supervisor from power plants shall read and collect data
from power and fuel meters at the end of every month.
(3) Copies of invoices for electricity and fuel (diesel and natural gas) supplies are stored by CDM
Manager for double checking.
Power plant manager
CDM Manager
Meter supervisor Data recorder
CDM consultant
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C. Data recording and archiving procedures
• The CDM Manager shall keep monitored data in electronic archives at the end of every month.
Paper documents should also be compiled and saved monthly.
• Power plant shall keep copies of electricity sales and fuel purchase invoices
• In order to help verifiers obtain documents and information related to the emission reduction of the
proposed project, CDM Manager shall prepare an index of the data documents compiled
• All the data shall be kept for 2 years after the crediting period.
D. Training
The CDM consultant will in close collaboration with the power plant manager train the CDM Manager to
ensure effective monitoring of all parameters in line with the monitoring plan.