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PROJECT DESIGN DOCUMENT FORM FOR CDM PROJECT ACTIVITIES (F-CDM-PDD) Version 04.1
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UNFCCC/CCNUCC
CDM – Executive Board Page 1
PROJECT DESIGN DOCUMENT FORM
FOR CDM PROJECT ACTIVITIES (F-CDM-PDD)
Version 04.1
PROJECT DESIGN DOCUMENT (PDD)
Title of the project activity Grid connected natural gas based power project
in Raigad District, Maharastra, India
Version number of the PDD Version 1.0
Completion date of the PDD 07/05/2012
Project participant(s) Pioneer Gas Power Limited (PGPL)
Host Party(ies) India
Sectoral scope and selected methodology(ies) Sectoral Scope: 1 Energy Industries-
(Renewable or Non-renewable)
Selected methodology: AM 0029 Baseline
Methodology for Grid Connected Electricity
Generation Plants using Natural Gas, Version
3.0
Estimated amount of annual average GHG
emission reductions
1505877 tCO2
UNFCCC/CCNUCC
CDM – Executive Board Page 2
SECTION A. Description of project activity
A.1. Purpose and general description of project activity
>>
Project activity comprises of green field, natural gas fired 388 MW Combined Cycle Gas Turbine
(CCGT) Technology power generation plant, being developed by Pioneer Gas Power Limited
(hereinafter called PGPL) in Raigad District, Maharastra, India. Electricity generated by the project
activity would be evacuated to the NEWNE region grid (project boundary) through the High-voltage
transmission network. In the absence of the project activity, the same amount of electricity would have
been generated by the coal based power plants which leads to more GHG emissions compared to the
Natural gas based power generation which is less carbon intensive fuel. Thus, the proposed project
activity leads to the reduction of the greenhouse gases (GHGs).
Scenario existing prior to start of implementation of project activity:
For the year 2011-12, electricity generation in India was 811.10 Billion Units (BU) of which coal alone
accounted for 535.3 BU representing 66%. Several national policy level documents, including National
Electricity Policy (Source: National Electricity Policy) and Working Group Report for the 11th Plan,
indicate that pulverised coal PC would be the dominant fuel for electricity generation. As per Ministry of
Power, India, the total installed capacity, as on March 20121, is 199,627 MW of which the majority of
share i.e 112,022 MW (56%) is coal based power plant. This establishes the fact that coal based power
plant is the most predominant technology for power generation in India.
Baseline Scenario
The applied baseline methodology AM0029 version 03 is based on the approach 48 (b) of CDM
modalities and procedures which state “Emissions from a technology that represents an economically
attractive course of action, taking into account barriers to investment” be applied for determining the
baseline scenario. Based on this, all the credible and plausible alternatives are analyzed in sec B.4 of the
PDD and most economically attractive alternative option is concluded to be power plant based on Coal as
fuel which would have been the most plausible baseline scenario for the project activity. The
identification of baseline scenario is explained in section B.4.
Project scenario:
The project scenario envisages the use of natural gas as fuel for power plant using combined cycle
technology. The proposed project includes one Gas Turbine Generator (GTG) with output capacity of
259 MW, One Heat recovery Steam Generator (HRSG) and a Steam Turbine Generator (STG) with
output rating of 129 MW, amounting to a total of 388 MW. The generated electricity is to be supplied to
the NEWNE grid and the detailed description is given in section A.3 of the PDD. The project activity is
estimated to result in average emissions reduction of 1505877 tCO2 annually and 15058770 tCO2 over the
chosen crediting period of ten years.
Contribution of the project activity to sustainable development
Government of India has stipulated the social, economical, environmental and technological well-being
as indicators of sustainable development of the nation2.The contribution of the project activity in the
sustainable development of the nation is as follows:
1 http://www.powermin.nic.in/JSP_SERVLETS/internal.jsp
2 http://envfor.nic.in:80/divisions/ccd/cdm_iac.html
UNFCCC/CCNUCC
CDM – Executive Board Page 3
(i) Social well being:
The project activity will provide direct and indirect employment opportunity for the local
population during the construction and operation of the plant.
Being a project which would provide significant employment potential, this also offers ample
scope for development of secondary small scale entrepreneurs such as tiny establishments and
shops in the nearby areas. The presence of these establishments would also provide social
security to the area.
It leads to infrastructure development in the vicinity of the project site by ease access of transport
facilities for the people living nearby.
It also contributes towards the improvement of the power position by decreasing the power
deficit in the grid.
ii) Environmental well being
The power generated by the natural gas which is a clean fuel would be the less carbon intensive
fuel compared to the other source of power generation.
It avoids the usage of fossil fuel such as coal, lignite, diesel, naphtha etc., for the same capacity
of power generation.
It also reduces GHG, fly ash and other particulate emissions into the atmosphere which would
have been emitted into the atmosphere in case of coal and lignite based power plants.
iii) Economic well being:
Due to the employment opportunities, the economic living standard of the local population
increases.
It also provides business opportunity to the local business people such as civil and electrical
material suppliers etc., in the region.
Upon registration as a CDM project activity, the project would earn CERs, a percentage of the
proceeds of which would be used for the cause of the common public in the area.
iv) Technological well being:
The proposed project activity is a natural gas based combined cycle power plant (CCPP) and it
has higher efficiency compared to an open cycle CCGT or coal or lignite based thermal power
plant of similar capacity. Thus, it adopts environmentally safe and sound technology.
The successful operation of new technology would increase the technical knowledge of the
power plant workers/operators due to the exposure of the new technology.
In view of the above, it is clear that the project activity contributes to the sustainable development of the
country. The project participant also plans to commit 2% of the revenue from the sale of CERs towards
the social welfare activities. The detailed note on the sustainable development is given in Appendix – 5
of the PDD.
UNFCCC/CCNUCC
CDM – Executive Board Page 4
A.2. Location of project activity
A.2.1. Host Party(ies)
>>
India
A.2.2. Region/State/Province etc.
>>
Maharastra
A.2.3. City/Town/Community etc.
>>
Raigad District
A.2.4. Physical/Geographical location
>>
The project activity will come up at MIDC Ville-Bhagad, Mangaon Taluk, Raigad District, Maharashtra,
India.
Nearest railway station : Mangaon and Kolad
Nearest air port : Mumbai and Pune
Distance from Mangaon town : 22 kms
Geographical coordinates : 73 deg 21’ to 73 deg 22.5’ Latitude and 18 deg 22’ to 18 deg 24
Longitude
A.3. Technologies and/or measures
>>
The proposed project activity is the natural gas based power plant of 388 MW capacity. This consist of
One (Gas Turbine Generator) GTG, One Steam Turbine Generator (STG) and a Heat Recovery Steam
generator (HRSG).
The project activity involves Combined Cycle Power Plant (CCPP) in which the natural gas is combusted
to generate high pressure gas. The high pressure exhaust drives the gas turbine which is connected with
the individual A.C. Generator by means of speed reduction gear box, which generates power of 259 MW.
The GT exhaust shall be connected to the HRSG through suitable ducts. The HP Steam system supplies
high pressure superheated steam from the superheater outlet of HRSG to the steam turbine. The LP steam
UNFCCC/CCNUCC
CDM – Executive Board Page 5
system consists of superheated steam from the HRSG, which are combined together and admitted into the
LP stage of steam turbine.
The Exhaust gas from the GTG at the temperature of 614°C passes through the HRSG to generate HP, IP
and LP steam and the steam generated is allowed to pass through the Steam Turbine Generator coupled
with the generator to generate power of 129 MW. The auxiliary steam requirements for steam turbine
auxiliaries such as gland sealing steam shall be catered from main steam line through suitable pressure
reducing and de-superheating stations (PRDS).
The exhaust from the HRSG will be discharged to atmosphere at 60 m above local grade level through
main stack.
The detailed technical specifications of the equipment is tabulated below
S. No Equipment Specifications
1. Gas Turbine Generator (GTG) Make & Type: GE- frame 9FA m/c,
Output: 259 MW, ISO Base Rating.
The GT exhaust temperature will be around 614°C.
2. Heat Recovery Steam Generator
(HRSG)
Unfired, Natural circulation, triple pressure type e.g.
HP steam, IP Steam and LP steam.
HP steam generating capacity of 257.2 TPH at 144.7
ata & 567 °C ,
IP steam of 305.2TPH, 22.71 ata, 566 °C and
LP steam of 29.86 TPH at 4.177 ata & 307 °C.
3. Steam Turbine Generator (STG) One (1) no. Multistage, single flow, condensing type
steam turbine with injection steam and with a radial
exhaust with a STG power output of 129 MW. The
steam pressure and temperature at the HP stage inlet
is 141.2 ata and 566 Deg C, IP stage inlet is 21.84 ata
& 566 deg C and LP stage inlet is 3.854 ata & 305
Deg C.
A.4. Parties and project participants
Party involved
(host) indicates a host Party
Private and/or public
entity(ies) project participants
(as applicable)
Indicate if the Party involved
wishes to be considered as
project participant (Yes/No)
India (host) Private entity : Pioneer Gas
Power Limited
No
A.5. Public funding of project activity
>>
Public funding from Annex I parties and diversion of official development assistance is not involved in
this project.
SECTION B. Application of selected approved baseline and monitoring methodology
B.1. Reference of methodology
>>
Title : Baseline Methodology for Grid Connected Electricity Generation Plants using Natural
Gas”, Version 03, Sectoral Scope : 01, EB 39
Reference : Approved baseline methodology AM0029,
UNFCCC/CCNUCC
CDM – Executive Board Page 6
http://cdm.unfccc.int/methodologies/PAmethodologies/approved.html
Tools Used:
Title : “Tool for the demonstration and assessment of additionality”, version 6.0, EB 65
Title : “Tool to calculate emission factor for an electricity system”, version 02.2.1, EB 63
B.2. Applicability of methodology
>>
Applicability condition as per AM0029 Justification
Condition 01
The project activity is the construction and
operation of a new natural gas fired grid-
connected electricity generation plant;
Footnote reference cited for Applicability
Condition – 01
Natural gas should be the primary fuel. Small
amounts of other start-up or auxiliary fuels can
be used, but can comprise no more than 1% of
total fuel use, on energy basis.
The condition is fulfilled as project activity is the
construction and operation of a new natural gas
fired plant of 388 MW capacity connected to
NEWNE grid of India.
Project is proposed to be operated with only
natural gas (including LNG) being used as fuel
and no secondary fuels will be used for
electricity generation. Start-up fuels used (if any)
in the project activity will be less than 1% of
total fuel being used on energy basis.
Applicability Condition-02
The geographical/physical boundaries of the
baseline grid can be clearly identified and
information pertaining to the grid and estimating
baseline emissions is publicly available;
The baseline grid for the proposed project is
NEWNE grid. The physical boundaries of the
baseline grid are identified and its information is
publicly available from Central Electricity
Authority, Government of India3.
Applicability Condition-03
Natural gas is sufficiently available in the region
or country, e.g. future natural gas based power
capacity additions, comparable in size to the
project activity, are not constrained by the use of
natural gas in the project activity.
Footnote reference cited for Applicability
Condition – 03
In some situations, there could be price supply
constraints (e.g., limited resources without
possibility of expansion during the crediting
period) that could mean that a project activity
With the recent numerous gas discoveries made
in India by both private firms and state run oil
companies post the ‘New Exploration Licensing
Policy’ (NELP) of Government of India’, natural
gas supply availability has substantially
increased for all the consuming sectors. The main
producers of natural gas are Oil & Natural Gas
Corporation Ltd. (ONGC), Oil India Limited
(OIL) and JVs of Tapti, Panna-Mukta and Ravva.
These existing reserves are expected to be
augmented further by the recent gas discoveries
in the KG basin. Reliance and Cairn Energy
announced discoveries of gas in the KG basin
with large estimated reserves. The Reliance
group and its alliance company, Niko Resources
found a large deepwater gas discovery offshore
3 http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
UNFCCC/CCNUCC
CDM – Executive Board Page 7
displaces natural gas that would otherwise be
used elsewhere in an economy, thus leading to
possible leakage. Hence it is important for the
project proponent to document that supply
limitations will not result in significant leakage
as identified here.
in the KG basin on block KG_DWN_98/3. The
total volume of gas reserves discovered by
Reliance is estimated to be about 219.70 BCM. A
new gas reserve was explored by reliance
industries surrounding D1 and D3 blocks of K-G
Basin with estimated reserve of 1-2 trillion cubic
feet of gas 4 . Further requisite infrastructure to
transport the LNG across the country is in place,
Hazira and Dahej terminal have expanded their
handling capacity from 2.5MMTPA to 3.6
MMTPA5
and 5 MMTPA to 10 MMTPA
respectively.
Utilization of Natural gas in the project activity
does not constrict the availability of natural gas
for future natural gas based power generation
capacity as evidenced by the national policy
documents which give a list of future planned gas
power plant capacity additions.
On the basis of the above it is concluded that
there are no price inelastic supply constraints for
natural gas that warrants leakage. Further a
separate note on surplus gas availability is
submitted to DoE for validation.
B.3. Project boundary
According to version 03 of AM0029, in the calculation of project emissions, only CO2 emissions from
fossil fuel combustion at the project plant are considered. In the calculation of baseline emissions, only
CO2 emissions from fossil fuel combustion in power plant(s) in the baseline are considered.
The greenhouse gases included in or excluded from the project boundary are shown in the table below.
Source GHGs Included? Justification/Explanation
Ba
seli
ne
scen
ari
o
Power
generation
in baseline
CO2 Yes Main emission source
CH4 No Excluded for simplification. This is
conservative.
N2O No Excluded for simplification. This is
conservative.
Pro
ject
scen
ari
o Onsite fuel
combustion
due to
project
activity
CO2 Yes Main emission source
CH4 No Excluded for simplification.
N2O No Excluded for simplification.
According to relevant methodology AM0029 version 03, the spatial extent of project boundary includes
the project site and all power plants connected physically to baseline grid as defined in “Tool to
4 http://www.tribuneindia.com/2010/20100410/biz.htm#2 5 MMTPA – million metric tonnes per annum
UNFCCC/CCNUCC
CDM – Executive Board Page 8
calculate emission factor for an electricity system”.
For the proposed project activity, the project boundary includes the project si te and the NEWNE
grid which is the baseline grid . Thus, the project boundary covers the one Gas Turbine Generator
(GTG), one heat recovery steam generator (HRSG), a Steam Turbine Generator (STG), associated
auxiliary equipment and all the power plants that are connected to the NEWNE grid.
B.4. Establishment and description of baseline scenario
>>
The baseline methodology for grid connected electricity generation plants using natural gas
AM0029 suggests using the following two steps to define the baseline scenario:
Step 1: Identify plausible baseline scenarios
In this step, all the possible realistic and credible alternatives that provide outputs or services
comparable with the proposed CDM project activity are identified.
The existing and planned available technologies of power generation within NEWNE grid are as
follows:
Natural Gas
Gas Turbine Generator
(GTG)
HRSG
Steam Turbine Generator
(STG)
Aux. consumption
NEWNE Grid
Combustion
Gas exhaust
UNFCCC/CCNUCC
CDM – Executive Board Page 9
S.No Alternative scenarios Output and services Permitted by
regulations
1 Project activity not undertaken as CDM
activity
Full year generation – base
load
yes
2 Natural gas based power generation in open
cycle
Full year generation – base
load
yes
3 Coal based power generation (Sub-critical
technology)
Full year generation – base
load
yes
4 Coal based power generation (Super-critical
technology)
Full year generation – base
load
yes
5 Lignite based power generation
Full year generation – base
load
yes
6 Wind based power generation Full year generation – peak
load
yes
7 Hydro power generation Full year generation – peak
load
yes
8 Power generation using Nuclear fuel
Full year generation – base
load
yes
9 Electricity import from other grid
Full year generation – base
load
yes
a) Project activity not undertaken as CDM activity
The natural gas project (388 MW) with a lifetime of 25 years6 is intended to supply power to the
NEWNE grid of India and it complies with all the legal and regulatory requirement. But the activity
would have faced barriers as discussed in section B.5 of the PDD.
b) Natural gas based power generation in open cycle mode (388 MW)
Power generation in open cycle mode can meet the base load requirement, but the system has got
very low system efficiency (25-35%7) as compared to the combined cycle because of the high
exhaust (heat) loss. Further it does not deliver comparable output to that of the project activity, hence
it is not considered as the credible alternative.
c) Coal based power generation (500 MW Sub-critical plant with a lifetime of 25-30 years8)
This alternative, in the efficiency range of 32-38%9, will meet the base load requirement of the grid
and is in compliance with all the legal requirement. Hence this option is a realistic and credible
alternative therefore considered further in the analysis.
d) Coal based power generation (Super-critical plant)
Super critical plant operates above the critical pressure of steam (221 bar) with a higher plant
efficiency in the range of 36-40%10. This technology is credited as least polluting with low ash
6 CERC Terms and conditions regulations, 2009
7http://books.google.co.in/books?id=KJOoQm3fbEoC&pg=PT433&lpg=PT433&dq=efficiency+of+open+cycle+power+plant&source=web&ots
=#v=onepage&q=efficiency%20of%20open%20cycle%20power%20plant&f=false 8 http://cercind.gov.in/160502/comp_bidding.pdf 9 http://www.energyjustice.net/files/coal/igcc/factsheet.pdf 10http://cea.nic.in/thermal/Special_reports/Report%20of%20the%20committee%20to%20recommend%20next%20higher%20size%20of%20coa
l%20fired%20thermal%20power%20stations.pdf
UNFCCC/CCNUCC
CDM – Executive Board Page 10
related problems and low fuel consumption for the same output as that of the sub-critical plant.
However the capital cost for the super critical technology is significantly higher. This option is considered
further in the analysis
e) Lignite based power generation
List of lignite based power plants connected to the NEWNE grid are given in the table below, it is
clearly evident that lignite based power plants are not found in Maharashtra region. These kinds of
plants are set up only near the lignite mines (Pit head) owing to the specific fuel characteristics of the
lignite. Since there are no such mines in the project activity region (Mahrashtra), this alternative is
not considered further.
Power Plant State Capacity, MW Year of
commissioning
Girial Rajasthan 125*2 2007
Kutch lignite Gujarat 70*2 and 75*2 2009
Surat lignite Gujarat 125*4 2010
Akrimota lignite Gujarat 125*2 2005
Jallippa kapurdi
TPP
Rajasthan 135*2 2010
Barsingar lignite Rajasthan 125*2 2011
f) Wind based power generation with low PLF11
Project activity caters to the base load requirement of the grid but wind mills cannot meet the base
load power requirement, moreover wind mill based power generation are volatile and are subjected
to seasonal variations. The same is also considered by Electricity Regulatory Commission of India
(Central12
and Maharastra State) for providing lower Capacity Utilisation Factor for determination of
tariff for power generated based on wind (i.e. 23% and 30% respectively capacity factor on an
average). Hence this alternative is not compared with the project activity in terms of services that it
delivers.
g) Hydro based power generation
‘Run-of-river’ and ‘reservoir based’ are the two types of hydro power generation. But both the
category is suited for meeting only the peak load13 requirement of the grid whereas the project
activity is for catering the base load. The plant load factor of hydro power plants is in the range of 40
-60% only. Hence this alternative is not considered in the analysis.
h) Power generation using Nuclear fuel
Nuclear energy based power generation is developed exclusively by Government of India (GoI), and
thus totally out of consideration for private companies. Nuclear option is available only to Nuclear
Power Corporation of India Limited, a 100% Government of India owned Company14
whose capacity
additions are driven by the Government of India initiatives based on its long term strategic
programmes.also Nuclear Power Corporation is not governed by the Indian Electricity Act, 2003 and
11 http://energymanagertraining.com/kaupp/Article28.pdf
12 CERC (Terms and Conditions for Tariff determination from Renewable Energy Sources) Regulations, 2009 dated 16 th September 2009 13 Hydro Sector Development in India (Growth & Investment Opportunities ) – By R.V.Shahi, Secretary, Ministry of Power, Government of
India July, 2003 14 http://www.world-nuclear.org/info/inf53.html
UNFCCC/CCNUCC
CDM – Executive Board Page 11
is not subject to jurisdiction of Indian Electricity Regulatory Commissions. Therefore this alternative
is excluded from the analysis.
i) Electricity import from other grid
Planned power capacity addition is being done by the Ministry of Power through the five year plans
Electricity Import from other regional grids in India is not a possible option as these grids are
suffering from shortages to meet their energy demand and in particular the peak demand. The energy
shortage during the year 2009-10 was -10.1% and the peak shortage was -12.7% for entire India.
Power deficit situations across regional grids in the year 2009-1015
Year Northern
region
Southern
Region
Eastern
region
Western
Region
North
Eastern
region
2009-10 - 11.6% - 6.4% - 4.4% - 13.7% - 11.1%
From the above table it is quite clear that power crisis exists in the entire regional grids and importing of
grid power is not a feasible option. Hence this option is ruled out of consideration.
After considering all the above mentioned alternatives, the comparable realistic alternatives that will
provide comparable output and service as that of CDM project activity are as follows:
Comparable Alternatives to the Proposed Project Activity:
Fuel Alternatives
Natural gas Combined cycle gas turbine
Coal Coal based power generation (sub-critical)
Coal Coal based power generation (super-critical)
B.5. Demonstration of additionality
>>
Step 2: Identify the economically most attractive baseline scenario alternative
According to the methodology, the economically most attractive baseline scenario has to be
identified by using investment analysis. The project proponent wishes to use levelised cost of
electricity generation as the financial indicator for all alternatives remaining after step 1. Include
all relevant costs (including, for example, the investment cost, fuel costs and operation and
maintenance costs), and revenues (including subsidies/fiscal incentives, ODA, etc. where
applicable), and, as appropriate, non-market costs and benefits in the case of public investors.
All power generation projects in India, levelized cost of electricity generation is a realistic approach to
perform comparisons among different technologies (alternatives) since it allows to quantify, the
unitary cost of the electricity (the kWh) generated during the lifetime of all the alternatives being
compared. The levelized cost of electricity being a mean value, allows the immediate comparison with
the cost of other alternatives. The consideration of all the affecting components in present money
worth in calculation of levelized cost of generation provides a level ground for comparison and
justifies its use as a suitable indicator. It is also important to note that for all power generation projects
15 http://cea.nic.in/reports/yearly/annual_rep/2009-10/ar_09_10.pdf
UNFCCC/CCNUCC
CDM – Executive Board Page 12
in India which are evaluated by Ministry of Power, Government of India, levelized cost of generation16
is the evaluation criteria.
The parameters have been sourced from national policy guidelines (CERC, terms and conditions of
tariff, 2009).
A. Assumptions for Natural gas based CCPP
Technical details Value Source
Capacity (MW) 388 EPC contract
PLF 85%
Central Electricity Regulatory Commission
(Terms & conditions of Tariff) Regulations, 2009
cercind.gov.in)
Discount factor 11% RBI guidelines; http://www.rbi.org.in
ROE 16% Central Electricity Regulatory Commission
(Terms & conditions of Tariff) Regulations, 2009
cercind.gov.in)
Auxiliary Consumption 3.0%
Annual O&M expenses 2.50%
Annual O&M Escalation 6.00%
Interest on Working Capital 11% RBI guidelines; http://www.rbi.org.in
Equity 30% Central Electricity Regulatory Commission
(Terms & conditions of Tariff) Regulations, 2009
cercind.gov.in)
Debt 70%
Annual fuel price escalation 7.00%
No. of Working days per annum 365
No. of Working hours per annum 8760
Project lifetime 25 Central Electricity Regulatory Commission
(Terms & conditions of Tariff) Regulations, 2009
cercind.gov.in)
Term Loan repayment period 9
Moratorium 1
B. assumptions for coal based power plant
Technical details Value Source
Capacity (MW) 500 Nearest block size available
PLF 80%
Central Electricity Regulatory Commission (Terms
& conditions of Tariff) Regulations, 2009
cercind.gov.in)
16 http://powermin.nic.in/whats_new/competitive_guidelines.htm
UNFCCC/CCNUCC
CDM – Executive Board Page 13
Discount factor 11% http://www.rbi.org.in
ROE 16% Central Electricity Regulatory Commission (Terms
& conditions of Tariff) Regulations, 2009
cercind.gov.in) Auxiliary Consumption 9.50%
Annual O&M expenses 2.50%
Annual O&M Escalation 6.00%
Equity 30%
Debt 70%
Gross calorific value (kCal/kg) 4,760
Data available from Singareni colliery; Price
notification and applicable taxes
No. of Working days per annum 365
No. of Working hours per annum 8760
Project lifetime 25
Central Electricity Regulatory Commission (Terms
& conditions of Tariff) Regulations, 2009
cercind.gov.in)
Term Loan repayment period 9
Moratorium 1
Annual Fuel price increase 4.00% IMF Database
Based on the above assumed parameters, the levelised cost of corresponding options for electricity
generation are calculated and listed below.
Levelised cost for Different Comparable Alternatives
Alternative Capacity Levelised Cost of Generation
CCGT Plant (without CDM benefits )
388 MW 3.54 INR/kWh
Coal-fired power plant 500 MW 2.00 INR/kWh
According to AM0029 Version 03 the assessment of additionality comprises the following steps:
Step 1: Investment Analysis
Step 2: Common Practice Analysis
Step 3: Impact of CDM Registration
If all 3 steps are satisfied, then the project is considered additional.
Step 1: Investment analysis
According to AM0029, Version 3, steps 2.b, 2.c and 2.d of the “Tool for the demonstration and
assessment of additionality” version 6.0 is applied to evaluate the additionality of the project.
Sub-step 2.b (Option III) – Apply benchmark Analysis
UNFCCC/CCNUCC
CDM – Executive Board Page 14
Levelised cost of generation (INR/kWh) is used as the financial indicator. The basis of choosing it as
financial indicator is indicated in the baseline scenario analysis.
Suitability of choosing the benchmark is further justified as follows:
For benchmark, the tool under Section 6 of the Sub-step 2 b of additionality tool, version 6.0
states”Discount rates and benchmarks shall be derived from:...”.
Paragraph d under sub-step (2b), option III of the additionality tool refers to a Government/official
approved benchmark where such benchmarks are used for investment decisions. There is no such
Government/official approved benchmark available for private sector power generation in the country.
Paragraph under sub-step (2b), option III of the additionality tool suggests the option of using any other
indicators, if the project participants can demonstrate that the above Options are not applicable and their
indicator is appropriately justified.
Given the above discussion, in the context of the project activity, the lowest levelised cost of power
generation amongst all the plausible baseline options, has been considered as the suitable benchmark.
Sub – step 2c. Calculation and Comparison of Financial Indicators Levelised cost for Different Comparable Alternatives
Alternative Capacity Levelised Cost of Generation
CCGT Plant (without CDM benefits )
388 MW 3.54 INR/kWh
Coal-fired power plant 500 MW 2.00 INR/kWh
The above table shows the proposed project activity is not the financially attractive option for the PP.
coal based power plant is the financially attractive option amongst the alternatives as it is
economically viable and technologically proven, hence considered as the benchmark. The project
activity’s levelised cost of generation is less than the benchmark therefore it is not financially
attractive.
Sub – step 2d. Sensitivity Analysis
AM0029, version 3 states:
“The range of the sensitivity analysis should cover, in a realistic way, the possible variations of
all key parameters that are related to the analysis and that could change over the crediting
period.”
The sensitivity analysis on levelized tariff for power generation using natural gas and coal are presented in
section B.4 above. It further substantiates that even with reasonable variations in the key variable e.g.
project cost, fuel price, SHR and PLF, power generation using natural gas as fuel continues to remain
amongst the more expensive alternatives and the same using coal as fuel with sub-critical technology is
economically the most attractive option. The sensitivity parameters that are likely to have impact on the
return of the project are: Cost of the project, Plant Load factor (PLF) and Station Heat Rate (SHR) and fuel
price as shown in Table below.
Sensitivity Analysis
UNFCCC/CCNUCC
CDM – Executive Board Page 15
A. Heat rate
Parameters -10% 0% 10%
Coal 1.87 2.00 2.13
Natural Gas 3.24 3.54 3.83
B. PLF
Parameters -10% 0% 10%
Coal 2.08 2.00 1.94
Natural Gas 3.60 3.54 3.49
C. Project cost
Parameters -10% 0% 10%
Coal 1.93 2.00 2.07
Natural Gas 3.48 3.54 3.59
D. Fuel cost
Parameters -10% 0% 10%
Coal 1.87 2.00 2.13
Natural Gas 3.24 3.54 3.83
Cost of the project can fluctuate due to escalation in costs of plant and equipment and unforeseen delays
in commissioning. Plant Load Factor can fluctuate due to many reasons such as unplanned shut down,
machinery failure duration of plant etc. Station Heat Rate (SHR) will be affected by the gas
consumption and efficiency of the project machinery. All these risks have been very much inherent
in the project. P P considered both positive and negative variations of the above mentioned
parameters. There is less probability for significant positive variations and the extent of negative
variation is not far from reasonable possibility.
The sensitivity of the project shows the robustness of the project activity in comparison to the baseline.
Also it is evident that in all the scenarios discussed, the project activity remains the unattractive option.
Step 2: Common Practice Analysis
Demonstrate that the project activity is not common practice in the relevant country and sector by
applying Step 4 (common practice Analysis) of the latest version of the “Tool for demonstration and
assessment of additionality” agreed by the CDM Executive Board.
As per step 4 of additionality tool, the project has to compliment additionality with Common practice
analysis as a credibility check.
Sub-step 4(a). Analyze other activities similar to the proposed project activity
UNFCCC/CCNUCC
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The common practice analysis have been carried out following the UNFCCC ‘Guidelines on common
practice’ (version 1.0, EB 63 Annex-12)
Step 1: Calculate applicable output range as +/-50% of the design output or capacity of the proposed
project activity.
The capacity of the project activity is 388 MW. Hence in accordance with step 1, the “applicable output
range” is determined as 194 MW (project capacity-50%) to 582 MW (project capacity + 50%).
Also, following the default choice as recommended in the guidelines on common practice (version 01.0, EB 63
Annex-12) the applicable geographical area has been considered as the entire host country i.e. India.
Step 2: In the applicable geographical area, identify all plants that deliver the same output or capacity,
within the applicable output range calculated in Step 1, as the proposed project activity and have started
commercial operation before the start date of the project. Note their number Nall registered CDM project
activities shall not be included in this step
Start date of the project activity is 09 Feb 2012, so those projects that have commenced operation prior to
this date are considered. The number of identified plants that deliver the same output or capacity within
the applicable output range calculated in Step 1 is 324, excluding registered CDM projects and the list is
given in annex 1.
Step 3: Within plants identified in Step 2, identify those that apply technologies different that the technology applied in the proposed project activity. Note their number Ndiff.
Different measures Technology applied No of power plants in
different technology
Fuel No of plants that run other than natural gas as fuel
(project activity operates on natural gas) 300
Feed stock No of plants that are designed to fire natural gas plus
other secondary fuels such as naptha, diesel etc
(project activity utilises only natural gas as fuel)
14
Investment climate No of plants that are developed by public entities
(project activity is being developed by private
entities)
7
Ndiff
321
Step 4: Calculate factor F=1-Ndiff/Nall representing the share of plants using technology similar to the technology used in the proposed project activity in all plants that deliver the same output or capacity as the proposed project activity. The share of plants using technology similar to the technology used in the proposed project activity in all plants that deliver the same output or capacity as the proposed project activity is:
F = 1-Ndiff / Nall
= 1 – 321/324 = 0.009259 Nall – Ndiff = 324 – 321 = 3
UNFCCC/CCNUCC
CDM – Executive Board Page 17
The value of F is 0.009259 and Nall – Ndiff =3, as per the guidance the proposed project activity is a ‘common practice’ within a sector in the applicable geographical area only if the factor F is greater than 0.2 and Nall-Ndiff is greater than 3. Hence it is concluded that the propose project activity is not a common practice in the geographical area.
Timeline of the proposed CDM project activity
The start date of the candidate project activity is considered as 09th February, 2012 (the date of Notice to
Proceed to the EPC contractor) which is after 2nd August, 2008. Hence prior consideration of CDM for the
project activity is demonstrated using the Guidelines on the Demonstration and Assessment of Prior
Consideration of the CDM, Version -04 (EB 62, Annex 13). The paragraph 2 of the guideline recommends
the following “The Board decided that for project activities with a starting date on or after 2 August 2008,
the project participant must inform a Host Party designated national authority (DNA) and the UNFCCC
secretariat in writing of the commencement of the project activity and of their intention to seek CDM status.
Such notification must be made within six months of the project activity start date and shall contain the
precise geographical location and a brief description of the proposed project activity, using the standardized
form F-CDM-Prior Consideration. Such notification is not necessary if a project design document (PDD)
has been published for global stakeholder consultation or a new methodology proposed to the Executive
Board for the specific project before the project activity start date.”
The project proponent has informed both the UNFCCC secretariat and the Host Party designated national
authority, of the commencement of the project activity and their intention to seek CDM status on 27th April
2012 which is within six months of the project activity start date.
In addition, the project proponent has initiated activities in order to secure CDM status parallel with the
project implementation. The chronology of events is presented in the table below in order to justify that
CDM were a decisive factor in the decision to proceed with the project activity.
Event Date Evidence
Notice to Proceed (NTP) 09th Feb 2012 NTP letter to EPC contractor
Prior consideration 27th April 2012 F-CDM form submitted to UNFCCC
and DNA
B.6. Emission reductions
B.6.1. Explanation of methodological choices
>>
The approved methodology AM0029, Version 03 “Methodology for Grid Connected Electricity
Generation Plants using Natural Gas” has been applied to the proposed project activity.
Project Emissions (PEy):
The project activity consists of on-site combustion of natural gas to generate electricity. Then, CO2
emissions from electricity generation (PEy) are calculated as follows using Eq. (1) of AM0029
PE y = FC f, y × COEF f, y (1)
Where,
FCf, y = is the total volume of fuel ‘f’ natural gas or other fuel combusted in the project plant (m3)
in year y
COEFf, y = is the CO2 emission coefficient (tCO2/m3) in year y for fuel f (natural gas / other fuel )
The emission coefficients of natural gas / other fuel are calculated as follows:
UNFCCC/CCNUCC
CDM – Executive Board Page 18
COEF f, y = NCV f, y × EFCO2, f, y × OXID f (1a)
Where,
NCVf, y = is the net calorific value of fuel ‘f’ natural gas / other fuel (GJ/m3), in year y, which is
determined from the fuel supplier.
EFCO2,f, y = is the CO2 emission factor per unit of energy of fuel f (natural gas / other fuel ) in year y
(tCO2/GJ), which is taken from the IPCC data.
OXIDf = is the oxidation factor of fuel f (natural gas / other fuel)
Baseline Emissions
As shown in the methodology AM0029, version 3, baseline emissions (tCO2e/year) are given by:
BEy = EGPJ,y × EFBL,CO2, y (2)
Where,
EGPJ,y = is the electricity generated by the power plant
EFBL,CO2,y= is the baseline carbon dioxide emission factor
According to methodology AM0029 / Version 03, there are uncertainties in the determination of an
appropriate value of the baseline emission factor EFBL,CO2. The methodology states in order to address
this uncertainty in a conservative manner, project participants shall use for EFBL,CO2,y the lowest emission
factor among the following three options:
For the first crediting period:
Option 1: The build margin, calculated according to “Tool to calculate emission factor for an
electricity system”; and
Option 2: The combined margin, calculated according to “Tool to calculate emission factor for an
electricity system”, using a 50/50 OM/BM weight
Option 3: The emission factor of the technology (and fuel) identified as the most likely baseline
scenario under “Identification of the baseline scenario” and calculated as follows:
EFBL,CO2 (tCO2 / MWh) = COEFBL / ηBL × 3.6GJ / MWh (3)
Where,
COEFBL = the fuel emission coefficient (tCO2e/GJ), based on national average fuel data, if
available, otherwise IPCC defaults can be used
ηBL = the energy efficiency of the technology, as estimated in the baseline scenario analysis
in the above section
Values of ‘build margin’ and ‘combined margin’ considered in Options 1 and 2 are taken from ‘CO2
Baseline Database for the Indian Power Sector’. The values are calculated as per procedures
prescribed in the “Tool to calculate emission factor for an electricity system” by Central Electricity
Authority (CEA). The database is an official publication of the Government of India for the purpose of
CDM Baselines and is based on the most recent data available with CEA.
As described in section B.4, the coal-based sub critical power plant has been identified as the
economically most attractive baseline. Eq. (3) then becomes
EFcoal ,CO2(tCO2/ MWh) = COEF/ / ηBL × 3.6GJ / MWh (3a)
UNFCCC/CCNUCC
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The emission coefficient COEFcoal can be calculated using an equation analogous to Eq (1a) above, but
applied to coal:
COEFcoal,y = NCVcoal,y × EFCO 2,coal , y × OXIDcoal (3b)
Where,
NCVcoal,y = is the net calorific value (energy content) per mass of coal
EFCO2,coal,y= is the CO2 emission factor per unit of energy of coal
OXIDcoal = is the oxidation factor of coal
Central Electricity Authority (CEA) values of NCVi and EFCO2,i are used.
Leakage
Leakage may result from fuel extraction, processing, liquefaction, transportation, regasification and
distribution of fossil fuels outside of the project boundary. This includes mainly fugitive CH4 emissions
and CO2 emissions from associated fuel combustion and flaring. In this methodology, the following
leakage emission sources shall be considered:
Fugitive CH4 emissions associated with fuel extraction, processing, liquefaction, transportation,
re-gasification and distribution of natural gas used in the project plant and fossil fuels used in the
grid in the absence of the project activity.
In the case LNG is used in the project plant: CO2 emissions from fuel combustion/electricity
consumption associated with the liquefaction, transportation, re-gasification and compression
into a natural gas transmission or distribution system.
Thus, leakage emissions are calculated as follows:
LE y = LECH 4,y + LE LNG ,CO 2, y (4)
Where,
LEy = Leakage emissions during the year y in tCO2e.
LECH 4,y = Leakage emissions due to fugitive upstream CH4 emissions in the year y in
tCO2e
LELNG,CO2,y = Leakage emissions due to fossil fuel combustion/electricity consumption associated
with liquefaction, transportation, re-gasification and compression of LNG into a
natural gas transmission or distribution system during the year y in t CO2e.
Fugitive Methane Emissions (LECH4, y)
For the purpose of estimating fugitive CH4 emissions, project participants should multiply the quantity of
natural gas consumed by the project in year y with an emission factor for fugitive CH4 emissions
(EFNG,upstream,CH4) from natural gas consumption and subtract the emissions occurring from fossil fuels
used in the absence of the project activity, as follows:
LECH 4, y = [FCy × NCVy × EFNG ,upstream, CH 4 - EGPJ , y × EFBL ,upstream, CH 4 ]× GWPCH4 (5)
Where,
LECH4,y = Leakage emissions due to fugitive upstream CH4 emissions in the year y in tCO2e
FCy = Quantity of natural gas combusted in the project plant during the year y in m3
NCV,y = Average net calorific value of the natural gas combusted during the year y in GJ/m3
EFNG,upstream,CH4 = Emission factor for upstream fugitive methane emissions of natural gas from
UNFCCC/CCNUCC
CDM – Executive Board Page 20
production, transportation, distribution and in the case of LNG, liquefaction,
transportation, re-gasification and compression into a transmission or distribution
system, in tCH4 per GJ of fuel supplied to final consumers
EGPJ,y = Electricity generation in the project plant during the year y in GWh.
EFBL,upstream,CH4 = Emission factor for upstream fugitive methane emissions occurring in the absence of
the project activity in tCH4 per GWh electricity generation in the project plant, as
defined below
GWPCH4 = Global warming potential of methane valid for the relevant commitment period
As per the applicable methodology, the emission factor for upstream fugitive CH4 emissions occurring in
the absence of the project activity EFBL,upstream,CH4 should be calculated consistent with the baseline
emission factor (EF BL, CO2) used in equation (2) above. Since the option 1 ‘build margin’ approach is
used to calculate the emission factor (EF BL, CO2), the EFBL,upstream,CH4 is found using the following equation
and it will be determined ex-post.
EFBL,upstream,CH4 = Emission factor for upstream fugitive methane emissions occurring in the absence of
the project activity in t CH4 per MWh electricity generation in the project plant
j = Plants included in the build margin
FFj,k = Quantity of fuel type k (a coal type) combusted in power plant j included in the
build margin
EFk,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k (a coal type) in t CH4 per MJ fuel produced
EGj = Electricity generation in the plant j included in the build margin in MWh/a
CO2 emissions from LNG
Project activity does not involve LNG, so LELNG,CO2,y is considered as ‘zero’ but, in case if LNG is used in
future then leakage due to that will be accounted for using the equation 6
LELNG,CO2,y = FCy * EFCO2,upstream, LNG (6)
Where:
LELNG,CO2,y = Leakage emissions due to fossil fuel combustion/electricity consumption associated
with the liquefaction, transportation, re-gasification and compression of LNG into a
natural gas transmission or distribution system during the year y in t CO2e
FCy = Quantity of natural gas combusted in the project plant during the year y in m³
EFCO2,upstream,LNG = Emission factor for upstream CO2 emissions due to fossil fuel combustion/electricity
consumption associated with the liquefaction, transportation, re-gasification and
compression of LNG into a natural gas transmission or distribution system
In the absence of the reliable and accurate EFCO2,upstream,LNG data, the default value of 6t CO2/TJ provided
by the methodology will be used.
UNFCCC/CCNUCC
CDM – Executive Board Page 21
Presently leakage due to CH4 fugitive upstream emissions is only accounted for. Then Eq. (4) becomes:
LE y = LECH 4 (4a)
Emission Reductions
To calculate the emission reductions the project participant shall apply the following equation:
ERy = BEy – PEy – LEy (7)
Where,
ERy = emissions reductions in year y (tCO2e)
BEy = emissions in the baseline scenario in year y (tCO2e)
PEy = emissions in the project scenario in year y(tCO2e)
LEy = leakage in year y (tCO2e)
B.6.2. Data and parameters fixed ex ante
(Copy this table for each piece of data and parameter.)
Data / Parameter EFBM,y
Unit tCO2e/GWh
Description Build Margin Emission Factor of NEWNE Grid
Source of data “CO2 Baseline Database for the Indian Power Sector” Version 7.0,
January 2012, published by the Central Electricity Authority, Ministry of
Power, Government of India.
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
Value(s) applied 858.78
Choice of data
or
Measurement methods
and procedures
CO2 Baseline Database is a publicly available national data, with high
level of reliability.
Purpose of data To estimate the baseline emissions
Additional comment
UNFCCC/CCNUCC
CDM – Executive Board Page 22
Data / Parameter EFOM,y
Unit tCO2e/GWh
Description Operting Margin Emission Factor of NEWNE Grid
Source of data “CO2 Baseline Database for the Indian Power Sector” Version 7.0,
January 2012, published by the Central Electricity Authority, Ministry of
Power, Government of India.
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
Value(s) applied 997.27
Choice of data
or
Measurement methods
and procedures
CO2 Baseline Database is a publicly available national data, with high
level of reliability.
Purpose of data To estimate the baseline emissions
Additional comment
Data / Parameter NCV coal
Unit kCal/ Kg
Description Net calorific value of coal
Source of data “CO2 Baseline Database for the Indian Power Sector” Version 7.0,
January 2012, published by the Central Electricity Authority, Ministry of
Power, Government of India.
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
Value(s) applied 3624.52 (GCV to NCV conversion done – 3755 kCal/kg /1.036 )
Choice of data
or
Measurement methods
and procedures
CO2 Baseline Database is a publicly available national data, with high
level of reliability.
Purpose of data To estimate the baseline emissions
Additional comment
UNFCCC/CCNUCC
CDM – Executive Board Page 23
Data / Parameter EFCO2,coal
Unit tCO2/TJ
Description Carbon di oxide emission factor of coal.
Source of data “CO2 Baseline Database for the Indian Power Sector” Version 7.0,
January 2012, published by the Central Electricity Authority, Ministry of
Power, Government of India.
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
Value(s) applied 95.8
Choice of data
or
Measurement methods
and procedures
CO2 Baseline Database is a publicly available national data, with high
level of reliability.
Purpose of data To estimate the baseline emissions
Additional comment
Data / Parameter OXIDcoal
Unit -
Description Oxidation Factor of Coal
Source of data “CO2 Baseline Database for the Indian Power Sector” Version 7.0,
January 2012, published by the Central Electricity Authority, Ministry of
Power, Government of India.
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
Value(s) applied 0.98
Choice of data
or
Measurement methods
and procedures
CO2 Baseline Database is a publicly available national data, with high
level of reliability.
Purpose of data To estimate the CO2 emission co-efficient and to calculate the baseline
emission
Additional comment
UNFCCC/CCNUCC
CDM – Executive Board Page 24
Data / Parameter ȠBL
Unit %
Description Power plant efficiency of the most likely baseline scenario technology.
Energy efficiency of coal fired power plant which has been identified as
the baseline scenario. It is assumed that baseline plant would be 500 MW
sub critical power plant based on Indigenous sub Bituminous coal or
imported coal.
Source of data Central Electricity Regulatory Commission (Terms & conditions of
Tariff) Regulations, 2009 for non-coking coal pit-head power generation.
www.cercind.gov.in
Value(s) applied 37.78 %
Choice of data
or
Measurement methods
and procedures
Central Electricity Regulatory Commission is Government of India
undertaking, mandated to publish information on performance of power
sector in India by the Indian Electricity Act 2003.
Purpose of data To estimate the baseline emissions
Additional comment
Data / Parameter EF NG, upstream, CH4
Unit t CH4 / GJ
Description Emission factor for upstream fugitive methane emissions of natural gas from
production, processing, transportation & distribution, and, in the case of
LNG, liquefaction, transportation, re-gasification and compression into a
transmission or distribution system.
Source of data Table- 2 of AM0029 version 3.0
Value(s) applied 0.00016
Choice of data
or
Measurement methods
and procedures
USA and Canada values have been used. Justification is given in
Appendix 4.
Purpose of data To estimate the fugitive CH4 emissions due to natural gas
Additional comment
B.6.3. Ex ante calculation of emission reductions
>>
Emission factors are calculated for all the three options:-
Option 1) Build margin
The value is taken from the ‘CO2 Baseline Database for the Indian Power Sector’ version 7 for the year
2010-11.
= 858.78 tCO2e/GWh
Option 2) Combined margin
UNFCCC/CCNUCC
CDM – Executive Board Page 25
The combined margin is a calculated value with a 50/50 OM/BM weights. The Operating Margin (OM)
and the Build Margin (BM) values are taken from the ‘CO2 Baseline Database for the Indian Power
Sector’ version 7.0. The Operating margin is fixed ex-ante and is taken as the average of the recent three
years data given by the CEA at the time of PDD submission.
Year Operating margin
2008-2009 1020.62 tCO2e/GWh
2009-2010 989.13 tCO2e/GWh
2010-2011 982.07 tCO2e/GWh
Therefore the operating margin is calculated to be
= (1020.62+989.13+982.07)/3
= 997.27 tCO2/GWh
And the combined margin is estimated as
= (0.5*997.27) + (0.5*858.78)
= 928.03 tCO2/GWh
Option 3) Emission factor of the identified baseline power plant
As described in section B.4, the coal-based sub critical power plant has been identified as the
economically most attractive baseline. Eq. (3) then becomes
EFcoal ,CO2(tCO2/ MWh) = COEF / ηBL × 3.6GJ / MWh (3a)
The emission coefficient COEFcoal is calculated using an equation analogous to Eq (1a) above, but
applied to coal:
COEFcoal,y = NCVcoal,y × EFCO2,coal , y × OXIDcoal (3b)
Where,
NCVcoal,y = is the net calorific value (energy content) per mass of coal
= 3624.52 kCal/kg
EFCO2,coal,y= is the CO2 emission factor per unit of energy of coal
= 95.80 t CO2/TJ
OXIDcoal = is the oxidation factor of coal
= 0.98
COEFcoal,y = 0.093884 tCO2e/GJ
EFcoal ,CO2(tCO2/ MWh) = (0.093883/37.78%)*3.6*1000
= 894.60 tCO2/ GWh
The minimum value among the three options is the build margin emission factor, i.e. EFgrid, BM,y = 858.78
tCO2/GWh, which is considered as the baseline emission factor.
Project Emissions (PEy):
PE y = FC f, y × COEF f, y
Where,
FCf, y = is the total volume of natural gas combusted in the Project plant (m3) in year y
UNFCCC/CCNUCC
CDM – Executive Board Page 26
= 505583400.00 m3
COEFf, y = is the CO2 emission coefficient (tCO2/m3) in year y for natural gas
The emission coefficient of natural gas is calculated as follows:
COEF f, y = NCV f, y × EFCO2, f, y × OXID f
Where,
NCVf, y = is the net calorific value of natural gas (GJ/ m3), in year y, which is determined
from the fuel supplier.
= 0.033488 GJ/ m3
EFCO2,f, y = is the CO2 emission factor per unit of energy natural gas in year y (tCO2/GJ), which is
taken from the IPCC data.
= 0.0561 tCO2/GJ
OXIDf = is the oxidation factor of natural gas
= 1
COEF f, y = 0.033488 * 0.0561 * 1
= 0.00187868 tCO2/m3
PE y = 0.00187868 * 505583400.00
= 949827.80 t CO2
Baseline Emissions
As shown in the methodology AM0029, version 3, baseline emissions (tCO2e/year) are given by:
BEy = EGPJ,y × EFBL,CO 2, y
Where,
EGPJ,y = is the electricity generated by the power plant, GWh
EFBL,CO2,y= is the baseline carbon dioxide emission factor, tCO2/GWh
= 2889 * 858.78
= 2481057 t CO2e
Leakage
LE y = LECH 4,y + LE LNG ,CO 2, y
Where,
LEy = Leakage emissions during the year y in tCO2e.
LECH 4,y = Leakage emissions due to fugitive upstream CH4 emissions in the year y in tCO2e
= 25351
LELNG,CO2,y= Leakage emissions due to fossil fuel combustion/electricity consumption associated
with liquefaction, transportation, re-gasification and compression of LNG into a natural
gas transmission or distribution system during the year y in t CO2e.
= 0
= 25351 + 0
= 25351 t CO2 e
Emission Reductions
ERy = BEy – PEy – LEy
Where,
ERy = emissions reductions in year y (tCO2e)
UNFCCC/CCNUCC
CDM – Executive Board Page 27
BEy = emissions in the baseline scenario in year y (tCO2e)
PEy = emissions in the project scenario in year y(tCO2e)
LEy = leakage in year y (tCO2e)
ERy = (2481057 - 949828 - 25351)
= 1505877 tCO2e
The excel file also shows the details of the calculations of baseline and project emissions, leakages and
emissions reduction. Determination of fugitive methane emissions and leakage emissions are detailed in
Appendix 4.
B.6.4. Summary of ex ante estimates of emission reductions
Year
Baseline
emissions
(t CO2e)
Project
emissions
(t CO2e)
Leakage
(t CO2e)
Emission
reductions
(t CO2e)
Year 1 2481057 949828 25351 1505877
Year 2 2481057 949828 25351 1505877
Year 3 2481057 949828 25351 1505877
Year 4 2481057 949828 25351 1505877
Year 5 2481057 949828 25351 1505877
Year 6 2481057 949828 25351 1505877
Year 7 2481057 949828 25351 1505877
Year 8 2481057 949828 25351 1505877
Year 9 2481057 949828 25351 1505877
Year 10 2481057 949828 25351 1505877
Total 9498280 24810570 253510 15058770
Total number of
crediting years
10
Annual
average over the
crediting period
2481057 949828 25351 1505877
B.7. Monitoring plan
B.7.1. Data and parameters to be monitored
(Copy this table for each piece of data and parameter.)
UNFCCC/CCNUCC
CDM – Executive Board Page 28
Data / Parameter EFBM,y
Unit tCO2e/GWh
Description Build Margin Emission Factor of NEWNE Grid
Source of data “CO2 Baseline Database for the Indian Power Sector” Version 7.0,
January 2012, published by the Central Electricity Authority, Ministry of
Power, Government of India. CO2 Baseline Database is a publicly
available national data, with high level of reliability.
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
Value(s) applied 858.78
Measurement methods
and procedures Not applicable
Monitoring frequency The parameter is calculated based on officially published national data, it
will be updated as per the latest ‘CO2 Baseline Database for the Indian
Power Sector’ available on year to year basis.
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate the baseline and leakage emissions
Additional comment Data will be archived for crediting period + 2 years
UNFCCC/CCNUCC
CDM – Executive Board Page 29
Data / Parameter FCf,y
Unit m3
Description Quantity of Natural Gas combusted in the project plant for the year, y
Source of data Fuel flow meter reading at the project boundary.
Value(s) applied 505583400.00
Measurement methods
and procedures
Data type: Measured
Data Archival: Paper & Electronic
Monitoring procedure and responsibility: Flow meter will be used in
monitoring of this parameter. The total fuel consumption will be monitored
both at supplier and project end for cross verification and measured in
standard cubic meters. CDM Manager will have the overall responsibility
for monitoring of this parameter
Calibration Procedures and frequency: In accordance with stipulation of
the meter supplier
Monitoring frequency Recording Frequency: continuous monitoring, recorded daily and reported
monthly
QA/QC procedures Quantity of natural gas consumed by the project activity will be cross-
checked with the invoices raised by the fuel supplier.
Purpose of data To estimate the project emissions
Additional comment Data will be archived for crediting period + 2 years
Data / Parameter FCLNG,y
Unit m3
Description Quantity of LNG combusted in the project plant for the year, y
Source of data Fuel flow meter reading at the project boundary.
Value(s) applied 0
Measurement methods
and procedures
Data type: Measured
Data Archival: Paper & Electronic
Monitoring procedure and responsibility: Flow meter will be used in
monitoring of this parameter. The total fuel consumption will be monitored
both at supplier and project end for cross verification and measured in
standard cubic meters. CDM Manager will have the overall responsibility
of monitoring this parameter
Calibration Procedures and frequency: In accordance with stipulation of
the meter supplier
Monitoring frequency Recording Frequency: continuous monitoring, recorded daily and reported
monthly
QA/QC procedures Quantity of natural gas consumed by the project activity will be cross-
verified with the invoices raised by the fuel supplier.
Purpose of data To estimate the project emissions on usage
Additional comment Data will be archived for crediting period + 2 years
UNFCCC/CCNUCC
CDM – Executive Board Page 30
Data / Parameter NCVf
Unit kCal/m3
Description Net calorific value of natural gas
Source of data Data from fuel supplier will be used
Value(s) applied 8000
Measurement methods
and procedures
Data type: Estimated
Data Archival: Electronic & Paper
Monitoring procedure and responsibility: The calorific value will be taken
from the supplier regularly. CDM Manager will have the overall
responsibility of monitoring this parameter.
Calibration Procedures: Not Applicable
Calibration Frequency: Not Applicable
Proportion of data monitored: 100%
Monitoring frequency Recording Frequency: Monitored and recorded fortnightly and reported
monthly
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate the project emissions
Additional comment Data will be archived for crediting period + 2 years
Data / Parameter EGPJ,y
Unit GWh / year
Description Net electricity generation in the project plant (delivered to the grid) during the
year y.
Source of data Data measured and recorded from Energy meters installed in the plant
complying with the regulatory requirement.
Value(s) applied 2822.60
Measurement methods
and procedures
Main and check meters are installed at all the outgoing lines as per the
applicable regulatory requirement.
Data type: Measured & calculated
Data Archiving Policy: Paper & Electronic
Monitoring procedure and responsibility: Energy meter will be used for
monitoring of this parameter. The accuracy class of this meter will be 0.2S.
CDM Manager will have the overall responsibility of monitoring this
parameter.
Calibration Procedures and frequency: As per (Govt / regulatory authority)
regulations.
Calibration Frequency: Annually
Proportion of data monitored: 100%
Monitoring frequency Recording Frequency: continuous monitoring, recorded daily and reported
monthly
QA/QC procedures The value will be crossed verified with the receipts raised by the power
distribution company as applicable.
Purpose of data To estimate the baseline emissions
Additional comment Data will be archived for crediting period + 2 years
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Data / Parameter EFCO2,f,y
Unit tCO2/GJ
Description CO2 Emission Factor of Natural Gas
Source of data Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines for National
Greenhouse Gas Inventories. This is also in conformity with the
recommendations of the GHG inventory information report submitted by
India’s Initial National Communication (Chapter 2)
Value(s) applied 0.0561
Measurement methods
and procedures
Data type: Estimated
Recording Frequency: Recorded annually
Data Archiving Policy: Paper & Electronic
Responsibility: CDM Manager will have the overall responsibility for
monitoring of this parameter.
Calibration Procedures: Not Applicable
Calibration Frequency: Not Applicable
Proportion of data monitored: 100%
Monitoring frequency The emission factor will be updated as per the latest IPCC information on
national greenhouse gas inventory available on year to year basis.
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate the project emissions
Additional comment Data will be archived for crediting period + 2 years
Data / Parameter OXIDf
Unit -
Description Oxidation Factor of Natural Gas
Source of data IPCC
Default values as per Table 1.6 Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories: Reference Manual has been considered. This is
also in conformity with the recommendations of the GHG inventory
information report submitted by India’s Initial National Communication
(Chapter 2)
Value(s) applied 1.0
Measurement methods
and procedures
Data type: Estimated
Recording Frequency: Recorded annually
Data Archiving Policy: Paper & Electronic
Responsibility: CDM Manager will have the overall responsibility for
monitoring of this parameter.
Calibration Procedures: Not Applicable
Calibration Frequency: Not Applicable
Proportion of data monitored: 100%
Monitoring frequency The Oxidation factor will be updated as per the latest IPCC information on
national greenhouse gas inventory available on year to year basis.
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate the project emissions
Additional comment Data will be archived for crediting period + 2 years
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Data / Parameter PE,y
Unit tCO2e
Description Project emission due to combustion of natural gas in the project activity
Source of data Calculated
Value(s) applied 949828
Measurement methods
and procedures
Data type: Calculated
Recording Frequency: Recorded annually
Data Archiving Policy: Paper & Electronic
Monitoring procedure and responsibility: The project emission will be
calculated on year to year basis. CDM Manager will have the overall
responsibility for monitoring of this parameter.
Calibration Procedures: Not Applicable
Calibration Frequency: Not Applicable
Proportion of data monitored: 100%
Monitoring frequency NA
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate emission reductions
Additional comment Data will be archived for crediting period + 2 years
Data / Parameter COEFf,y
Unit tCO2/m3
Description CO2 Emission coefficient for natural gas
Source of data Calculated
Value(s) applied COEFf,y = ΣNCVy * EFCO2f,f,y * OXIDf
= 0.00187868 tCO2/m3
Measurement methods
and procedures
Data type: Calculated
Recording Frequency: Recorded annually
Data Archiving Policy: Paper & Electronic
Monitoring procedure and responsibility: The CO2 emission coefficient
will be calculated on year to year basis. CDM Manager will have the
overall responsibility for monitoring of this parameter.
Calibration Procedures: Not Applicable
Calibration Frequency: Not Applicable
Proportion of data monitored: 100%
Monitoring frequency NA
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate the project emissions
Additional comment Data will be archived for crediting period + 2 years
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Data / Parameter EFBL,upstream,CH4
Unit tCH4/MWh
Description Emission factor for upstream fugitive methane emissions occurring in the
absence of the project activity electricity generation
Source of data Calculated using CEA CO2 baseline database or calculated based on CEA
data in case the database is not updated. EFBL,upstream,CH4 is calculated for
power plants included in the Build Margin, inline with the baseline
emission factor selection. Therefore in line with the AM0029 requirement
of ex-post determination of the Build Margin, the Emission factor for
upstream fugitive methane emissions occurring in the absence of the
project activity electricity generation (tCH4/MWh) will also be determined
ex-post.
Value(s) applied
0.00051981
Measurement methods
and procedures
Data type: Calculated
Recording Frequency: Recorded annually
Data Archiving Policy: Paper & Electronic
Monitoring procedure and responsibility: The EFBL,upstream,CH4 is computed
annually based on the latest information available in the CO2 baseline
database published by CEA. CDM Manager will have the overall
responsibility for monitoring of this parameter.
Calibration Procedures: Not Applicable
Calibration Frequency: Not Applicable
Proportion of data monitored: 100%
Monitoring frequency As per requirement
QA/QC procedures No additional QA/QC procedures may need to be planned
Purpose of data To estimate leakage
Additional comment Data will be archived for crediting period + 2 years
B.7.2. Sampling plan
>>
Not applicable
B.7.3. Other elements of monitoring plan
>>
1. The Monitoring plan
The monitoring plan describes management systems and procedures to be implemented by PGPL upon
project implementation in order to ensure consistent project operation as well as monitoring, processing
and reporting of data required for the calculation of emission reductions (ERs) taking into account the
methodology AM0029 requirement and the guidance presented in the Validation and Verification
Standards.
2. Description of organizational structures & procedures for collection, processing, review, storage
and reporting of data
The organization structure and responsibility matrix for this CDM project activity is as below:
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CDM Organization Structure:
CDM Manager is vested with the power to direct the O&M team, and fuel team, CDM team to:
a) Provide all information/data required for this monitoring plan
b) Comply with all the requirements as per the Project Design Document and Monitoring Plan.
c) Adherence to the laid down protocols, procedures and processes, in relation to CDM project
activity, by the aforesaid O & M team, fuel team and the CDM team
d) Refer all conflicts, discrepancies, mistakes etc in relation to the Monitoring Plan of the CDM
project activity, to the CDM manager for resolution, whose resolution in this regard shall be final
and binding on the aforesaid teams. The O&M team is headed by the Head, O & M and the Fuel
team is headed by the Fuel Manager.
3. CDM Responsibility Matrix:
S.No Designation Responsibilities
1. Director Implement the organization structure. Issue office orders, authorizing the
CDM Manager to implement the Monitoring plan and delegating to him
all powers in relation thereto
2. CDM
Manager
Direct the O& M team, fuel team, CDM team in relation to conformance with PDD and monitoring plan Storage of aggregated data. Coordinate with DOE during verification process. Monitor raw data in relation to Build Margin, Oxidation factor and where national institutions data / AM0029 default data are involved. Independently check the authenticity of data and take corrective actions wherever required. Resolve all conflicts in relation to CDM project activity. Calculate ER and submit them to DOE. Implement the Monitoring Plan
3. O & M
Team Calibrate the identified monitoring equipment and maintain data.
Monitor raw data as per enclosed task 4. CDM Team Data review, d a t a p r o c e s s i n g a n d a g g r e g a t i o n , Monitoring
plan, Report non-conformances with PDD, and CDM manager's
directions
5. Fuel
Manager Monitor raw data as per enclosed task
The following table provides detailed information on the organizational structures & procedures for
collection, processing, review, storage and reporting of data during operation of the project activity.
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Table 3.1: Organizational Structures and Procedures for Monitoring, Processing, Review, Storage,
and Transfer
Project Emissions Baseline
Parameters Emissions
FC NG,y NCV NG,y EGy
Monitoring of Responsible Head O&M Fuel Manager Head O&M
raw data person at PGPL
Data source Flow meter Fuel supplier(s) / Electricity
transporter(s ) meters
Frequency Daily Fortnightly Hourly
of data measurement,
collection monthly
recording
Data format Electronic Electronic Electronic
Data Procedures of As per N/A As per
processing maintenance and
calibration of
monitoring
equipment
calibration and
maintenance
protocol
calibration and
maintenance
protocol
Responsible CDM Team
person at PGPL
Description
of procedure
Consistency check, validation and recording
Frequency Daily Monthly Daily
of processing
Data review Responsible
CDM Team
Monthly/yearly person at
aggregation of
data
PGPL
Storage of data Responsible person
at PGPL
CDM Manager
Frequency of
storage
Monthly
Duration of Data will be archived for crediting period + 2 years
storage
Electricity generation at the project activity (CCPP) is at 15.75 kV which is then stepped-up to 200kV,
before power evacuation is done at the sub station level through two nos double circuit transmission
lines. Grid interfacing is done through 15.75/200kV, using generator step-up transformers located at the
plant premises. Metering arrangements are in place to measure the electricity supplied, through the
200kV transmission line, to the NEWNE grid from PGPL switch yard.
The electricity generation by power station for supply and the fuel consumption are measured by
electricity meter and flow meter respectively. Following guidelines will be followed for the A) Data
Monitoring B) Calibration and maintenance and C) Verification of monitoring results.
A) Data Monitoring
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The data that will be monitored include:
a) Monitoring of electricity generated by the project: The electricity generated by the project will
be monitored through energymeter at the plant. The data can also be monitored and recorded at
the on-site control center using a computer system.
There will be main metering system and backup metering system with accuracy class of 0.2
Calibration test records will be maintained for verification.
b) Monitoring of quantity of gas combusted: Quantity of gas (including LNG if used) combusted
will be monitored through metering equipments. Detailed monitoring procedure of quantity of
gas combusted by the project will be established in accordance with the agreements with the gas
suppliers and gas transporter. Calibration test records will be maintained for verification.
c) Monitoring of NCV: The NCV of gas is used in the calculation of CO2 emission coefficient.
Hence the NCV of gas from the fuel supplier will be maintained.
B) Calibration and Maintenance
The detailed calibration, testing and maintenance procedures for all the identified monitoring instrument
shall be prepared by the CDM Manager based on the agreements with the fuel supplier(s), equipment
manufacturer's recommendations and the industry /national standards as applicable.
C) Verification of Monitoring Results
The verification of the monitoring results of the project is mandatory process required for all CDM
projects.
The responsibilities for verification of the project are as follows:
The CDM Manager will arrange for the verification and will prepare for the audit and
verification process.
The CDM Manager will facilitate the verification process by providing the DOE with all required
necessary information.
Organizational structures & procedures during project implementation
Before the start of the crediting period the CDM Manager will develop the following protocols whose
functions are described below, based upon the organizational structures & procedures described in this
MP.
Data handling protocol
The establishment of a transparent system for the collection, computation and storage of data, including
adequate record keeping and data monitoring systems is required. It is the CDM Manager's responsibility
with the assistance of CDM team to ensure implementation of a protocol that provides for these critical
functions and processes. For electronic -based and paper-based data entry and recording systems, there
must be clarity in terms of the procedures and protocols for collection and entry of data, usage of the
spreadsheets and any assumptions made, so that compliance with requirements can be assessed by the
DOE.
Stand-by processes and systems, e.g. paper-based systems, must be outlined and used in the event of, and
to provide for, the possibility of systems failures.
Training protocol
It is the CDM Manager's responsibility to ensure that the required capacity and internal training is made
available to assigned staff, to enable them to undertake the tasks required by this MP. All staff involved
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in any of the procedures will be trained before the start of the crediting period in order to perform the
tasks specified in this MP. For this purpose a training protocol will be prepared.
Calibration and maintenance protocol
It is the CDM Manager's responsibility to ensure that the calibration and maintenance procedures for all
measurement instruments relevant for monitoring the parameters included in this MP are followed. A
calibration and maintenance protocol will be established for this purpose which will be prepared by the
CDM manager based on the agreements with the fuel supplier(s), equipment manufacturer's
recommendations and the applicable industry / national standards.
Data review protocol
It is the CDM Manager's responsibility to prepare a data review protocol that in case of failure of an
instrument, or inconsistency of the data, enables staff to adjust the data according to the procedures
outlined in this protocol. The data review protocol shall also include procedures for emergency
preparedness for cases where emergencies can cause unintended emissions.
SECTION C. Duration and crediting period
C.1. Duration of project activity
C.1.1. Start date of project activity
>>
09/02/2012, Notice to Proceed (NTP) issued to the Engineering Procurement and Construction (EPC)
contractor
C.1.2. Expected operational lifetime of project activity
>>
25 years and 0 months
C.2. Crediting period of project activity
C.2.1. Type of crediting period
>>
Fixed crediting period
C.2.2. Start date of crediting period
>>
09/10/2012 or date of registration whichever is later
C.2.3. Length of crediting period
10 years and 0 months
SECTION D. Environmental impacts
D.1. Analysis of environmental impacts
>>
Rapid Environmental Impact Assessment (REIA) Report is a statutory prerequisite for obtaining
Environment clearance from Ministry of Environment & Forest (MoEF), Government of India (GoI)
under the Environmental (Protection) Act 1986. By notification of the Government of India in the
Ministry of Environment and Forests, vide number S.O.1533(E), dated 14th September, 2006 the
required construction of new projects or activities or the expansion or modernization of existing projects
shall be undertaken in any part of India only after prior environmental clearance. REIA study is aimed at
predicting the possible environmental impacts due to construction and operation of the project,
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suggesting environmental remedies/safeguards and formulating an effective Environmental Mitigation
Plan to ensure an environmentally sustainable development.
The major environmental disciplines studied include geology, soils, surface & ground water hydrology,
meteorology, land use, surface & ground water quality, air quality, terrestrial & aquatic ecology,
demography & socio economics and noise.
REIA was conducted for the project by M/s Sd engineering services private limited it was found that
there would be reduced emissions; which includes huge emissions of carbon dioxide, sulphur dioxide,
oxides of nitrogen and particulate matter that would have occurred in absence of this project in baseline
scenario. Another advantage is that the project reduced adverse impacts related to air emission at coal
mines, as well as elimination of required for transportation of coal that would have been required to
meet the additional capacity requirement of coal based thermal power stations. In case of the project
activity the fugitive dust emissions and release of effluents will be significantly lower due to the absence
of coal and ash handling plants associated with ash disposal areas for solid waste disposal.
Air Environment:
The height of each HRSG stack proposed is 60 m and that of bypass stack is 30 m for effective
dispersion of pollutants. As per the designed parameters, the net concentration of the gases will be below
the national ambient air quality standard (NAAQS). Hence, no significant impacts on air quality due to
the project activity implementation are envisaged.
Water Environment:
The water effluents will be treated and discharged to evaporation pond after meeting the standards. The
steam turbine is a condensing turbine; hence, there is very little water effluent. Hence, there will not be
any impact on surface/ground water within the study area of the power plant.
Noise:
Adequate measures will be taken for noise control apart from the extensive greenbelt existing in
the power plant.
The land is located within Maharashtra Industrial Development Corporation-MIDC area and there is no
human resettlement is involved.
Emergency Preparedness:
Adequate safety measures will be taken-up to tackle emergency.
No significant impacts have been identified in the REIA study.
D.2. Environmental impact assessment
>>
REIA study did not indicate any significant environmental impacts. However, mitigative measures have
been taken up for lesser impacts, as per details provided in D.1. Regular monitoring of all significant
environmental parameters is essential to check the compliance status vis-à-vis the environmental laws
and regulations. The objectives of the monitoring will be as follows:
To verify the results of the impact assessment study with respect to the proposed project.
To study the trend of ‘concentration values’ of the parameters, which have been identified as
critical and for which mitigative measures are planned.
To check and assess the efficiency of pollution control equipment.
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To ensure that any additional parameters, other than those identified in the impact, do not
become critical after the commissioning of the project activity.
All necessary steps will be taken to monitor the efficiency of pollution control equipment on regular
basis. Regular monitoring and vigilance of the surrounding environmental quality will be done. All
necessary stipulations and legal requirements of Maharastra Pollution Control Board (MPCB) and MoEF
will be fully complied.
Though this project may have insignificant adverse impact on the biological environment, if all the
recommended mitigative measures are followed, then the impacts will be manageable and, affect a very
limited area. The adverse impact will be greatly offset by the many positive socio-economic impacts that
will flow directly from the project.
PGPL has prepared an Environment Management Plan (EMP) to ensure mitigating measures for all kind
of environmental issues. The EMP is a part of Rapid Environment Impact Assessment (REIA). The EMP
aims at controlling pollution at the source level to the possible extent with the available and affordable
technology followed by treatment measures before they are discharged.
EMP aims at the preservation of the ecosystem by considering the pollution abatement facilities at the
plant inception. In the project power plant, pollution abatement has become an integral part of planning
and design along with techno economic factor.
The project is likely to have impacts on the community lifestyle (day to day activity of the people living
near the plant. Project participant is committed to develop the surrounding area in a manner that balances
consistently the societal & environmental requirements while safeguarding the environmental and social
features. Implementing a public relations strategy; employing locals; buying local goods and services;
encouraging local entrepreneurship, involving women participation in conservation efforts and creating
awareness about environmental health and pollution and encouraging respect for local traditions and
religious beliefs (all of them on reasonable endeavor basis) will offset the negative environmental
impacts.
SECTION E. Local stakeholder consultation
E.1. Solicitation of comments from local stakeholders
>>
The Local Stakeholder Consultation meeting to discuss stakeholder concerns on proposed Clean
Development Mechanism (CDM) project of Pioneer Gas Power Limited (PGPL) at MIDC, Vile-Bhagad,
Mangaon Taluk, Raigad District, Maharashtra was conducted on 3rd
May, 2012.
PGPL invited the local stakeholders for the meeting through notices dated 17/04/2012.
Venue : PGPL project office
Date : 3rd
May, 2012 Thursday
Time : 10:30 AM to 12:00 PM
The meeting was attended by several stake-holders including representatives from government agencies
(MIDC), Panchayat Surpanch, technology supplier, Contractors, Operation and Maintenance personnel,
PGPL employees and other participants from the vicinity of the plant.
The meeting began with an introductory note by Mr. Suhan Rao, Director, PGPL; upon Mr. Suhan Rao’s
request to select one of the participants to chair the meeting, the participants unanimously choose
Mr.Mahadev Thukaram Tamhamnkar, Surpanch, Vile-Bhagad Gram Panchayat.
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Upon the Chairperson’s approval, Mr. M. Sasi Kumar, General Manager, (Projects), PGPL made a brief
presentation covering the following topics:
The phenomenon of global warming
Kyoto Protocol and the objective of the same - how this was formed and the necessity to do the
CDM.
What is important in CDM and the objectives of the same
How this helps the local community
Importance of Local Stakeholder Consultation process
The proposed CDM project activity by PGPL
Technology used by the project activity
The environmental benefits of going for NG based power generation
Credentials of the project proponent PGPL
Once the presentation was over the stake holders were requested to share their thoughts about this project
and the floor was open to questions.
E.2. Summary of comments received
>>
As all the queries were satisfactorily answered, the stakeholders were satisfied with the project,
employment opportunity which will help to the overall development of the Region.
E.3. Report on consideration of comments received
>>
No adverse comments (or comments that require any action by the project proponent) on the candidate
project activity were received during the Local Stakeholder Consultation process.
SECTION F. Approval and authorization
>>
PP has yet to get the approval from the Host Country.
- - - - -
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Appendix 1: Contact information of project participants
Organization name Pioneer Gas Power Limited
Street/P.O. Box 8-2-311/C , Mithila Nagar, Road No. 10, Banjara Hills
Building -
City Hyderabad
State/Region Andhra Pradesh
Postcode 500 034
Country India
Telephone
Fax
Website -
Contact person
Title Managing Director
Salutation Mr.
Last name Kalvakuntla
Middle name -
First name Suhan Rao
Department
Mobile
Direct fax +91-40-2354 2921
Direct tel. +91-40-2354 2895, 2354 2920
Personal e-mail [email protected]
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Appendix 2: Affirmation regarding public funding
Public funding from Annex I and diversion of official development assistance is not involved
in this project. The project cost is met by the project participant by own sources and in part by
the debt finance from banks.
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Appendix 3: Applicability of selected methodology
Please refer section B.2 above
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Appendix 4: Further background information on ex ante calculation of emission reductions
CALCULATION OF FUGITIVE METHANE EMISSIONS AND LEAKAGE EMISSIONS
FACTOR
According to AM0029, version 3, “Leakage may result from fuel extraction, processing, liquefaction,
transportation, re-gasification and distribution of fossil fuels outside of the project boundary.”
Leakage emissions are calculated using the following equation:-
LE y = LECH 4,y + LE LNG ,CO2, y
Where,
LEy = Leakage emissions during the year y in tCO2e
LECH 4,y = Leakage emissions due to fugitive upstream CH4 emissions in the year y in
tCO2e
LELNG,CO2,y = Leakage emissions due to fossil fuel combustion/electricity consumption associated
with liquefaction, transportation, re-gasification and compression of LNG into a
natural gas transmission or distribution system during the year y in t CO2e.
Fugitive Methane Emissions (LECH4, y)
LECH 4, y = [FCy × NCVy × EFNG ,upstream, CH 4 - EGPJ , y × EFBL ,upstream, CH 4 ]× GWPCH4
As per the applicable methodology, the emission factor for upstream fugitive CH4 emissions occurring in
the absence of the project activity EFBL,upstream,CH4 should be calculated consistent with the baseline
emission factor (EF BL, CO2) used in equation (2). Since the option 1 ‘build margin’ approach is used to
calculate the emission factor (EF BL, CO2), the EFBL,upstream,CH4 is found using the following equation and it
will be determined ex-post.
EFBL,upstream,CH4 = Emission factor for upstream fugitive methane emissions occurring in the absence of
the project activity in t CH4 per MWh electricity generation in the project plant
j = Plants included in the build margin
FFj,k1 = Quantity of fuel type k1 (coal) combusted in power plant j included in the
build margin
= 257154365 tonnes/year
EFk1,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k1 (a coal type) in t CH4 per kilo tonne of fuel produced
= 0.8 t CH4 per kt
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FFj,k2 = Quantity of fuel type k2 (lignite) combusted in power plant j included in the
build margin
= 5672884 tonnes/year
EFk2,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k2 (lignite type) in t CH4 per kilo tonne of fuel produced
= 0.8 t CH4 per kt
FFj,k3 = Quantity of fuel type k3 (natural gas) combusted in power plant j included in the
build margin
= 13745371291 m3/year
EFk3,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k3 (natural gas) in t CH4 per PJ of fuel produced
= 160 t CH4 per PJ
FFj,k4 = Quantity of fuel type k4 (oil) combusted in power plant j included in the build margin
= 478525841.58 m3/year
EFk4,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k4 (oil) in t CH4 per PJ of fuel produced
= 4.1 t CH4 per PJ
FFj,k5 = Quantity of fuel type k5 (diesel) combusted in power plant j included in the
build margin
= 2672843.21 m3/year
EFk5,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k5 (natural gas) in t CH4 per PJ of fuel produced
= 4.1 t CH4 per PJ
FFj,k6 = Quantity of fuel type k6 (naptha) combusted in power plant j included in the
build margin
= 2211573548.46m3/year
EFk6,upstream,CH4 = Emission factor for upstream fugitive methane emissions from production of the fuel
type k6 (naptha) in t CH4 per PJ of fuel produced
= 4.1 t CH4 per PJ
EGj = Electricity generation in all the plants’ j’ included in the build margin in MWh/a
= 561338714 MWh
EFBL,upstream,CH4 = {(257154365*0.8) +( 5672884*0.8) + (13745371291*8800*160) + (478525841.58*
10100* 4.1) + (2672843.21*10500*4.1) + (2211573548.46*11300*4.1)} / 561338714
= 0.000519 t CH4 / MWh
Justification of the values taken in the calculations above:
National level data on fugitive emission factor for the fuels considered are not available; hence the
default values given by the Meth are taken.
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Coal
Coal production in India is done by Coal India Ltd (CIL) through its subsidiaries and by Singareni
Collieries Company Limited (SCCL). Open-case or surface mining forms nearly 90% of coal production
methods in both CIL and SCCL and this is evident from the link
http://www.coal.nic.in/cpdanx.htm#Annexure-IV. Therefore coal surface mining value of 0.8
tCH4/ktonne of coal from Table 2 of the methodology is taken as the fugitive CH4emissions factor value.
Lignite
Neither IPCC nor AM0029 specifies an emission factor for lignite, therefore the conservative value
corresponding to open coal mining i.e 0.8 tCH4/ktonne of lignite is taken for calculation. Moreover
lignite is also produced by surface mining method and this can be verified from Neyveli Lignite
Corporation’s (NLC) website, the leading producer of lignite in India:
http://www.nlcindia.com/about/about_01b.htm.
Natural gas
We use the same fugitive emissions factor as in the project case, i.e 160 tCH4/PJ (Table 2 of the
methodology – USA and Canada)
Oil, Diesel and Naptha
Value of 4.1tCH4/PJ for oil is taken as the fugitive CH4 emissions factor as per Table 2 of the
methodology. In absence of fugitive CH4 emission factor national data / IPCC / AM0029 value for Diesel
and Naptha, conservative value corresponding to oil is taken for calculation.
Note that net calorific value is used in each case, and for some fuels a conversion is needed from gross
calorific value and “Delta GCV-NCV” both provided by the official Central Electricity Authority
database used for determination of the CO2 emissions factor of the grid.
LECH 4, y = [FCy × NCVy × EFNG ,upstream, CH 4 - EGPJ , y × EFBL ,upstream, CH 4 ]× GWPCH4
FCy = Quantity of natural gas combusted in the project plant during the year y in m3
= 505583400 m
3
NCV,y = Average net calorific value of the natural gas combusted during the year y in GJ/m3
= 0.033488000 GJ/m
3
EFNG,upstream,CH4 = Emission factor for upstream fugitive methane emissions of natural gas from
production, transportation, distribution and in the case of LNG, liquefaction,
transportation, re-gasification and compression into a transmission or distribution
system, in tCH4 per GJ of fuel supplied to final consumers
= 0.000160 tCH4 per GJ
EGPJ,y = Electricity generation in the project plant during the year y in MWh
= 2889048 MWh
EFBL,upstream,CH4 = Emission factor for upstream fugitive methane emissions occurring in the absence of
the project activity in tCH4 per MWh electricity generation in the project plant
= 0.000519 t CH4 / MWh
GWPCH4 = Global warming potential of methane valid for the relevant commitment period
= 21
UNFCCC/CCNUCC
CDM – Executive Board Page 47
LECH 4, y = ((505583400* 0.033488000 * 0.000160) – (2889048 * 0.000519)) * 21
LECH 4, y= 25351.38 tCO2e
LE LNG ,CO2,y is considered as ZERO since LNG is not utilised in the project activity.
There fore,
LE y = LECH 4,y + LE LNG ,CO2, y
= 25351.38 + 0
= 25351.38 tCO2e
UNFCCC/CCNUCC
CDM – Executive Board Page 48
Appendix 5: Further background information on monitoring plan
2% CER revenue commitment for socio economic development by the PP
PP will ensure corporate social responsibility is met by undertaking the following socio economic
development activities from the CER revenue realized by the project activity.
Providing healthcare facilities to the needy people
Improving infrastructural facilities viz building construction for the schools, laying of roads etc
Assisting the rural students by way of distributing books, uniforms and scholarships etc
Undertaking other developmental activities in consultation with local panchayat
Participating in other social welfare scheme of own or conducted by others
Funding to the Non Governmental Organization for the social welfare activities
These activities will be implemented either directly or by equivalent monetary donations to the
organizations working in these areas and sectors.
UNFCCC/CCNUCC
CDM – Executive Board Page 49
Appendix 6: Summary of post registration changes
Not applicable
UNFCCC/CCNUCC
CDM – Executive Board Page 50
Annex 1 List of plants for common practice analysis17
Name Date of
comm
Cap
(MW) Sector Type Fuel 1 Fuel 2
CDM
statu
s
BARAUNI 310 STATE THERMAL COAL OIL No
KAHALGAON 31-Mar-92 210 CENTER THERMAL COAL OIL No
KAHALGAON 17-Mar-94 210 CENTER THERMAL COAL OIL No
KAHALGAON 24-Mar-95 210 CENTER THERMAL COAL OIL No
KAHALGAON 18-Mar-96 210 CENTER THERMAL COAL OIL No
KAHALGAON 31-Mar-07 500 CENTER THERMAL COAL OIL No
KAHALGAON 16-Mar-08 500 CENTER THERMAL COAL OIL No
KAHALGAON 31-Jul-09 500 CENTER THERMAL COAL OIL No
TENUGHAT 14-Apr-94 210 STATE THERMAL COAL OIL No
TENUGHAT 10-Oct-96 210 STATE THERMAL COAL OIL No
JOJBERA 427.5 PVT THERMAL COAL OIL No
CHANDRAPURA 4-Nov-09 250 CENTER THERMAL COAL OIL No
CHANDRAPURA 31-Mar-09 250 CENTER THERMAL COAL OIL No
DURGAPUR 5-Dec-81 210 CENTER THERMAL COAL OIL No
BOKARO B 24-Mar-86 210 CENTER THERMAL COAL OIL No
BOKARO B 7-Nov-90 210 CENTER THERMAL COAL OIL No
BOKARO B 31-Mar-93 210 CENTER THERMAL COAL OIL No
MEJIA 21-Dec-95 210 CENTER THERMAL COAL OIL No
MEJIA 24-Mar-97 210 CENTER THERMAL COAL OIL No
MEJIA 25-Mar-98 210 CENTER THERMAL COAL OIL No
MEJIA 12-Oct-04 210 CENTER THERMAL COAL OIL No
MEJIA 31-Mar-07 250 CENTER THERMAL COAL OIL No
MEJIA 1-Oct-07 250 CENTER THERMAL COAL OIL No
TALCHER 470 CENTER THERMAL COAL OIL No
I.B.VALLEY 22-May-94 210 STATE THERMAL COAL OIL No
I.B.VALLEY 22-Oct-95 210 STATE THERMAL COAL OIL No
TALCHER STPS 19-Feb-95 500 CENTER THERMAL COAL OIL No
TALCHER STPS 27-Mar-96 500 CENTER THERMAL COAL OIL No
TALCHER STPS 4-Jan-03 500 CENTER THERMAL COAL OIL No
TALCHER STPS 25-Oct-03 500 CENTER THERMAL COAL OIL No
TALCHER STPS 13-May-04 500 CENTER THERMAL COAL OIL No
TALCHER STPS 6-Feb-05 500 CENTER THERMAL COAL OIL No
BANDEL 8-Oct-82 210 STATE THERMAL COAL OIL No
SANTALDIH 7-Nov-07 250 STATE THERMAL COAL OIL No
KOLAGHAT 13-Aug-90 210 STATE THERMAL COAL OIL No
KOLAGHAT 16-Dec-85 210 STATE THERMAL COAL OIL No
KOLAGHAT 24-Jul-84 210 STATE THERMAL COAL OIL No
17
http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm
UNFCCC/CCNUCC
CDM – Executive Board Page 51
KOLAGHAT 28-Dec-93 210 STATE THERMAL COAL OIL No
KOLAGHAT 17-Mar-91 210 STATE THERMAL COAL OIL No
KOLAGHAT 16-Jan-93 210 STATE THERMAL COAL OIL No
BAKRESWAR 18-Jul-99 210 STATE THERMAL COAL OIL No
BAKRESWAR 20-May-00 210 STATE THERMAL COAL OIL No
BAKRESWAR 21-Mar-01 210 STATE THERMAL COAL OIL No
BAKRESWAR 23-Dec-07 210 STATE THERMAL COAL OIL No
BAKRESWAR 7-Jun-09 210 STATE THERMAL COAL OIL No
D.P.L. 24-Nov-07 300 STATE THERMAL COAL OIL No
TITAGARH 240 PVT THERMAL COAL OIL No
BUDGE BUDGE 16-Sep-97 250 PVT THERMAL COAL OIL No
BUDGE BUDGE 6-Mar-99 250 PVT THERMAL COAL OIL No
BUDGE BUDGE 12-Jul-09 250 PVT THERMAL COAL OIL No
FARAKKA STPS 1-Jan-86 200 CENTER THERMAL COAL OIL No
FARAKKA STPS 24-Dec-86 200 CENTER THERMAL COAL OIL No
FARAKKA STPS 6-Aug-87 200 CENTER THERMAL COAL OIL No
FARAKKA STPS 25-Sep-92 500 CENTER THERMAL COAL OIL No
FARAKKA STPS 16-Feb-94 500 CENTER THERMAL COAL OIL No
FARAKKA STPS 23-Mar-11 500 CENTER THERMAL COAL OIL No
MUZAFFARPUR 220 CENTER THERMAL COAL OIL No
SAGARDIGHI TPP 21-Dec-07 300 STATE THERMAL COAL OIL No
SAGARDIGHI TPP 20-Jul-08 300 STATE THERMAL COAL OIL No
KATHALGURI GT 291 CENTER THERMAL GAS n/a No
BADARPUR 2-Dec-78 210 CENTER THERMAL COAL OIL No
BADARPUR 25-Dec-81 210 CENTER THERMAL COAL OIL No
I.P.GT 270 STATE THERMAL GAS DISL No
PRAGATI CCGT 330.4 STATE THERMAL GAS n/a No
PANIPAT 28-Mar-89 210 STATE THERMAL COAL OIL No
PANIPAT 1-Apr-01 210 STATE THERMAL COAL OIL No
PANIPAT 26-Sep-04 250 STATE THERMAL COAL OIL No
PANIPAT 28-Jan-05 250 STATE THERMAL COAL OIL No
F_BAD CCGT 431.59 CENTER THERMAL GAS NAPT No
GHTP (LEH.MOH.) 29-Dec-97 210 STATE THERMAL COAL OIL No
GHTP (LEH.MOH.) 16-Oct-98 210 STATE THERMAL COAL OIL No
GHTP (LEH.MOH.) 3-Jan-08 250 STATE THERMAL COAL OIL No
GHTP (LEH.MOH.) 31-Jul-08 250 STATE THERMAL COAL OIL No
ROPAR 26-Sep-84 210 STATE THERMAL COAL OIL No
ROPAR 29-Mar-85 210 STATE THERMAL COAL OIL No
ROPAR 31-Mar-88 210 STATE THERMAL COAL OIL No
ROPAR 29-Jan-89 210 STATE THERMAL COAL OIL No
ROPAR 29-Mar-92 210 STATE THERMAL COAL OIL No
ROPAR 30-Mar-93 210 STATE THERMAL COAL OIL No
KOTA 25-Sep-88 210 STATE THERMAL COAL OIL No
UNFCCC/CCNUCC
CDM – Executive Board Page 52
KOTA 1-May-89 210 STATE THERMAL COAL OIL No
KOTA 26-Mar-94 210 STATE THERMAL COAL OIL No
KOTA 30-Jul-03 195 STATE THERMAL COAL OIL No
KOTA 30-May-09 195 STATE THERMAL COAL OIL No
SURATGARH 10-May-98 250 STATE THERMAL COAL OIL No
SURATGARH 28-Mar-00 250 STATE THERMAL COAL OIL No
SURATGARH 29-Oct-01 250 STATE THERMAL COAL OIL No
SURATGARH 25-Mar-02 250 STATE THERMAL COAL OIL No
SURATGARH 30-Jun-03 250 STATE THERMAL COAL OIL No
SURATGARH 29-Aug-09 250 STATE THERMAL COAL OIL No
ANTA GT 419.33 CENTER THERMAL GAS NAPT No
OBRA 26-Jan-80 200 STATE THERMAL COAL OIL No
OBRA 14-Jan-79 200 STATE THERMAL COAL OIL No
OBRA 31-Dec-77 200 STATE THERMAL COAL OIL No
OBRA 28-Mar-81 200 STATE THERMAL COAL OIL No
OBRA 21-Jul-82 200 STATE THERMAL COAL OIL No
PARICHA 29-Mar-06 210 STATE THERMAL COAL OIL No
PARICHA 28-Dec-06 210 STATE THERMAL COAL OIL No
ANPARA 1-Jan-87 210 STATE THERMAL COAL OIL No
ANPARA 8-Jan-87 210 STATE THERMAL COAL OIL No
ANPARA 1-Apr-89 210 STATE THERMAL COAL OIL No
ANPARA 3-Jan-94 500 STATE THERMAL COAL OIL No
ANPARA 1-Oct-94 500 STATE THERMAL COAL OIL No
SINGRAULI STPS 13-Feb-82 200 CENTER THERMAL COAL OIL No
SINGRAULI STPS 25-Nov-82 200 CENTER THERMAL COAL OIL No
SINGRAULI STPS 28-Mar-83 200 CENTER THERMAL COAL OIL No
SINGRAULI STPS 2-Nov-83 200 CENTER THERMAL COAL OIL No
SINGRAULI STPS 26-Feb-84 200 CENTER THERMAL COAL OIL No
SINGRAULI STPS 23-Dec-86 500 CENTER THERMAL COAL OIL No
SINGRAULI STPS 24-Nov-87 500 CENTER THERMAL COAL OIL No
RIHAND 31-Mar-88 500 CENTER THERMAL COAL OIL No
RIHAND 5-Jul-89 500 CENTER THERMAL COAL OIL No
RIHAND 31-Jan-05 500 CENTER THERMAL COAL OIL No
RIHAND 24-Sep-05 500 CENTER THERMAL COAL OIL No
UNCHAHAR 21-Nov-88 210 CENTER THERMAL COAL OIL No
UNCHAHAR 22-Mar-89 210 CENTER THERMAL COAL OIL No
UNCHAHAR 27-Jan-99 210 CENTER THERMAL COAL OIL No
UNCHAHAR 22-Oct-99 210 CENTER THERMAL COAL OIL No
UNCHAHAR 28-Sep-06 210 CENTER THERMAL COAL OIL No
DADRI (NCTPP) 21-Dec-91 210 CENTER THERMAL COAL OIL No
DADRI (NCTPP) 18-Dec-92 210 CENTER THERMAL COAL OIL No
DADRI (NCTPP) 16-Jun-92 210 CENTER THERMAL COAL OIL No
DADRI (NCTPP) 24-Mar-94 210 CENTER THERMAL COAL OIL No
UNFCCC/CCNUCC
CDM – Executive Board Page 53
DADRI (NCTPP) 29-Jan-10 490 CENTER THERMAL COAL OIL No
DADRI (NCTPP) 30-Jul-10 490 CENTER THERMAL COAL OIL No
TANDA 440 CENTER THERMAL COAL OIL No
GIRAL 250 STATE THERMAL LIGN OIL No
DHOLPUR 330 STATE THERMAL GAS n/a No
YAMUNANAGAR TPP 13-Nov-07 300 STATE THERMAL COAL OIL No
YAMUNANAGAR TPP 13-Nov-07 300 STATE THERMAL COAL OIL No
UKAI_Coal 21-Jan-79 200 STATE THERMAL COAL OIL No
UKAI_Coal 28-Mar-79 200 STATE THERMAL COAL OIL No
UKAI_Coal 30-Jan-85 210 STATE THERMAL COAL OIL No
GANDHI NAGAR 20-Mar-90 210 STATE THERMAL COAL OIL No
GANDHI NAGAR 20-Jul-91 210 STATE THERMAL COAL OIL No
GANDHI NAGAR 17-Mar-98 210 STATE THERMAL COAL OIL No
DHUVARAN CCPP 218.62 STATE THERMAL GAS n/a No
WANAKBORI 23-Mar-82 210 STATE THERMAL COAL OIL No
WANAKBORI 15-Jan-83 210 STATE THERMAL COAL OIL No
WANAKBORI 15-Mar-84 210 STATE THERMAL COAL OIL No
WANAKBORI 9-Mar-86 210 STATE THERMAL COAL OIL No
WANAKBORI 23-Sep-86 210 STATE THERMAL COAL OIL No
WANAKBORI 18-Nov-87 210 STATE THERMAL COAL OIL No
WANAKBORI 31-Dec-98 210 STATE THERMAL COAL OIL No
SIKKA REP. 240 STATE THERMAL COAL OIL No
KUTCH LIG. 290 STATE THERMAL LIGN OIL No
ESSAR GT IMP. 10-Aug-95 515 PVT THERMAL GAS NAPT No
TORR POWER SAB. 310 PVT THERMAL COAL OIL No
G.I.P.C.L. GT 305 PVT THERMAL GAS NAPT No
SURAT LIG. 500 PVT THERMAL LIGN OIL No
PAGUTHAN 11-Dec-98 250 PVT THERMAL GAS NAPT No
GANDHAR GT 30-Mar-95 224.49 CENTER THERMAL GAS n/a No
SATPURA 30-Mar-79 200 STATE THERMAL COAL OIL No
SATPURA 20-Sep-80 210 STATE THERMAL COAL OIL No
SATPURA 25-Jan-83 210 STATE THERMAL COAL OIL No
SATPURA 27-Feb-84 210 STATE THERMAL COAL OIL No
KORBA-V 30-Mar-07 250 STATE THERMAL COAL OIL No
KORBA-V 12-Dec-07 250 STATE THERMAL COAL OIL No
KORBA-WEST 21-Jun-83 210 STATE THERMAL COAL OIL No
KORBA-WEST 30-Mar-84 210 STATE THERMAL COAL OIL No
KORBA-WEST 26-Mar-85 210 STATE THERMAL COAL OIL No
KORBA-WEST 13-Mar-86 210 STATE THERMAL COAL OIL No
AMAR KANTAK EXT 15-Jun-08 210 STATE THERMAL COAL OIL No
SANJAY GANDHI 26-Mar-93 210 STATE THERMAL COAL OIL No
SANJAY GANDHI 27-Mar-94 210 STATE THERMAL COAL OIL No
SANJAY GANDHI 28-Feb-99 210 STATE THERMAL COAL OIL No
UNFCCC/CCNUCC
CDM – Executive Board Page 54
SANJAY GANDHI 23-Nov-99 210 STATE THERMAL COAL OIL No
SANJAY GANDHI 27-Aug-08 500 STATE THERMAL COAL OIL No
KORBA STPS 1-Mar-83 200 CENTER THERMAL COAL OIL No
KORBA STPS 31-Oct-83 200 CENTER THERMAL COAL OIL No
KORBA STPS 17-Mar-84 200 CENTER THERMAL COAL OIL No
KORBA STPS 31-May-87 500 CENTER THERMAL COAL OIL No
KORBA STPS 25-Mar-88 500 CENTER THERMAL COAL OIL No
KORBA STPS 23-Feb-89 500 CENTER THERMAL COAL OIL No
KORBA STPS 26-Dec-10 500 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 10-Oct-87 210 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 23-Jul-88 210 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 3-Feb-89 210 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 26-Dec-89 210 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 31-Mar-90 210 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 1-Feb-91 210 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 3-Mar-99 500 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 26-Feb-00 500 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 27-Jul-06 500 CENTER THERMAL COAL OIL No
VINDH_CHAL STPS 8-Mar-07 500 CENTER THERMAL COAL OIL No
NASIK 31-Mar-79 210 STATE THERMAL COAL OIL No
NASIK 10-Jul-80 210 STATE THERMAL COAL OIL No
NASIK 30-Jan-81 210 STATE THERMAL COAL OIL No
KORADI 31-Mar-78 200 STATE THERMAL COAL OIL No
KORADI 30-Mar-82 210 STATE THERMAL COAL OIL No
KORADI 13-Jan-83 210 STATE THERMAL COAL OIL No
K_KHEDA II 26-Mar-89 210 STATE THERMAL COAL OIL No
K_KHEDA II 8-Jan-90 210 STATE THERMAL COAL OIL No
K_KHEDA II 31-May-00 210 STATE THERMAL COAL OIL No
K_KHEDA II 7-Jan-01 210 STATE THERMAL COAL OIL No
PARAS 31-Mar-08 250 STATE THERMAL COAL OIL No
PARAS 27-Mar-10 250 STATE THERMAL COAL OIL No
BHUSAWAL 28-Mar-79 210 STATE THERMAL COAL OIL No
BHUSAWAL 4-May-82 210 STATE THERMAL COAL OIL No
PARLI 20-Sep-80 210 STATE THERMAL COAL OIL No
PARLI 26-Mar-85 210 STATE THERMAL COAL OIL No
PARLI 31-Dec-87 210 STATE THERMAL COAL OIL No
PARLI 16-Feb-07 250 STATE THERMAL COAL OIL No
PARLI 10-Feb-10 250 STATE THERMAL COAL OIL No
CHANDRAPUR_Coal 15-Aug-83 210 STATE THERMAL COAL OIL No
CHANDRAPUR_Coal 11-Jul-84 210 STATE THERMAL COAL OIL No
CHANDRAPUR_Coal 3-May-85 210 STATE THERMAL COAL OIL No
CHANDRAPUR_Coal 8-Mar-86 210 STATE THERMAL COAL OIL No
CHANDRAPUR_Coal 22-Mar-91 500 STATE THERMAL COAL OIL No
UNFCCC/CCNUCC
CDM – Executive Board Page 55
CHANDRAPUR_Coal 11-Mar-92 500 STATE THERMAL COAL OIL No
CHANDRAPUR_Coal 1-Oct-97 500 STATE THERMAL COAL OIL No
TROMBAY_Coal 25-Jan-84 500 PVT THERMAL COAL OIL No
TROMBAY_Coal 30-Sep-09 250 PVT THERMAL COAL OIL No
DHANU 6-Jan-95 250 PVT THERMAL COAL OIL No
DHANU 29-Mar-95 250 PVT THERMAL COAL OIL No
RATNAGIRI GAS 11-Dec-98 240 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 11-Dec-98 240 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 11-Dec-98 225 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 30-Apr-06 240 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 7-May-06 240 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 14-May-06 260 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 28-Oct-07 240 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 28-Oct-07 240 PVT THERMAL NAPT GAS No
RATNAGIRI GAS 28-Oct-07 260 PVT THERMAL NAPT GAS No
AKRIMOTA LIG 250 STATE THERMAL LIGN OIL No
SIPAT STPS 27-May-07 500 CENTER THERMAL COAL OIL No
SIPAT STPS 27-Dec-08 500 CENTER THERMAL COAL OIL No
RAIGARH TPP 8-Dec-07 250 PVT THERMAL COAL OIL No
RAIGARH TPP 6-Mar-08 250 PVT THERMAL COAL OIL No
RAIGARH TPP 10-Feb-07 250 PVT THERMAL COAL OIL No
RAIGARH TPP 17-Jun-08 250 PVT THERMAL COAL OIL No
BHILAI TPP 20-Apr-08 250 CENTER THERMAL COAL OIL No
BHILAI TPP 12-Jul-09 250 CENTER THERMAL COAL OIL No
SUGEN CCCP 20-Nov-08 382.5 PVT THERMAL GAS n/a Yes
(Ref
no:
1116)
SUGEN CCCP 7-May-09 382.5 PVT THERMAL GAS n/a
SUGEN CCCP 8-Jun-09 382.5 PVT THERMAL GAS n/a
CHHABRA TPS 30-Oct-09 250 STATE THERMAL COAL OIL No
CHHABRA TPS 4-May-10 250 STATE THERMAL COAL OIL No
UTRAN CCCP EXT 10-Jul-09 228 STATE THERMAL GAS n/a No
ROSA TPP PH - 1 10-Feb-10 300 PVT THERMAL COAL OIL No
ROSA TPP PH - 1 26-Jun-10 300 PVT THERMAL COAL OIL No
PATHADI TPS PH -I 4-Jun-09 300 PVT THERMAL COAL OIL No
PATHADI TPS PH -I 25-Mar-10 300 PVT THERMAL COAL OIL No
MUNDRA TPP PH-I 4-Aug-09 330 PVT THERMAL COAL OIL No
MUNDRA TPP PH-I 17-Mar-10 330 PVT THERMAL COAL OIL No
MUNDRA TPP PH-I 2-Aug-10 330 PVT THERMAL COAL OIL No
MUNDRA TPP PH-I 20-Dec-10 330 PVT THERMAL COAL OIL No
JALLIPPA KAPURDI
TPP 270 PVT THERMAL LIGN OIL
No
BARSINGAR
LIGNITE 250 CENTER THERMAL LIGN OIL
No
WARDHA WARORA 405 PVT THERMAL COAL OIL No
PRAGATI CCCP -III 24-Oct-10 250 STATE THERMAL GAS No
UNFCCC/CCNUCC
CDM – Executive Board Page 56
PRAGATI CCCP -III 14-Feb-11 250 STATE THERMAL GAS No
MEJIA TPS EXT 30-Sep-10 500 CENTER THERMAL COAL OIL No
MEJIA TPS EXT 26-Mar-11 500 CENTER THERMAL COAL OIL No
INDRA GANDHI STPP 31-Oct-10 500 CENTER THERMAL COAL OIL No
JSW RATNAGIRI TPP 24-Aug-10 300 PVT THERMAL COAL OIL No
JSW RATNAGIRI TPP 9-Dec-10 300 PVT THERMAL COAL OIL No
K_GUDEM NEW 27-Mar-97 250 STATE THERMAL COAL OIL No
K_GUDEM NEW 28-Feb-98 250 STATE THERMAL COAL OIL No
VIJAYWADA 1-Nov-79 210 STATE THERMAL COAL OIL No
VIJAYWADA 10-Oct-80 210 STATE THERMAL COAL OIL No
VIJAYWADA 5-Oct-89 210 STATE THERMAL COAL OIL No
VIJAYWADA 23-Aug-90 210 STATE THERMAL COAL OIL No
VIJAYWADA 31-Mar-94 210 STATE THERMAL COAL OIL No
VIJAYWADA 24-Feb-95 210 STATE THERMAL COAL OIL No
RAYAL SEEMA 27-Apr-94 210 STATE THERMAL COAL OIL No
RAYAL SEEMA 25-Feb-95 210 STATE THERMAL COAL OIL No
RAYAL SEEMA 25-Jan-07 210 STATE THERMAL COAL OIL No
RAYAL SEEMA 20-Nov-07 210 STATE THERMAL COAL OIL No
RAYAL SEEMA 31-Dec-10 210 STATE THERMAL COAL OIL No
VIJESWARAN GT 272.3 STATE THERMAL GAS NAPT No
R_GUNDEM STPS 26-Nov-83 200 CENTER THERMAL COAL OIL No
R_GUNDEM STPS 29-May-84 200 CENTER THERMAL COAL OIL No
R_GUNDEM STPS 13-Dec-84 200 CENTER THERMAL COAL OIL No
R_GUNDEM STPS 26-Jun-88 500 CENTER THERMAL COAL OIL No
R_GUNDEM STPS 26-Mar-89 500 CENTER THERMAL COAL OIL No
R_GUNDEM STPS 16-Oct-89 500 CENTER THERMAL COAL OIL No
R_GUNDEM STPS 26-Sep-04 500 CENTER THERMAL COAL OIL No
SIMHADRI 22-Feb-02 500 CENTER THERMAL COAL OIL No
SIMHADRI 24-Aug-02 500 CENTER THERMAL COAL OIL No
SIMHADRI 31-Mar-11 500 CENTER THERMAL COAL OIL No
JEGURUPADU GT
216.82
4 PVT THERMAL GAS NAPT
No
GODAVARI GT 208 PVT THERMAL GAS NAPT No
KONDAPALLI GT 5-Dec-09 233 PVT THERMAL GAS NAPT No
PEDDAPURAM CCGT 8-Nov-02 220 PVT THERMAL GAS NAPT No
RAICHUR 29-Mar-85 210 STATE THERMAL COAL OIL No
RAICHUR 2-Mar-86 210 STATE THERMAL COAL OIL No
RAICHUR 30-Mar-91 210 STATE THERMAL COAL OIL No
RAICHUR 29-Sep-94 210 STATE THERMAL COAL OIL No
RAICHUR 31-Jan-99 210 STATE THERMAL COAL OIL No
RAICHUR 22-Jul-99 210 STATE THERMAL COAL OIL No
RAICHUR 11-Dec-02 210 STATE THERMAL COAL OIL No
RAICHUR 26-Jun-10 250 STATE THERMAL COAL OIL No
TORANGALLU IMP 260 PVT THERMAL COAL OIL/COREX No
UNFCCC/CCNUCC
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TANIR BAVI 220 PVT THERMAL GAS NAPT No
KAYAM KULAM GT 350 CENTER THERMAL GAS NAPT No
ENNORE 450 STATE THERMAL COAL OIL No
TUTICORIN 9-Jul-79 210 STATE THERMAL COAL OIL No
TUTICORIN 17-Dec-80 210 STATE THERMAL COAL OIL No
TUTICORIN 16-Apr-82 210 STATE THERMAL COAL OIL No
TUTICORIN 11-Feb-92 210 STATE THERMAL COAL OIL No
TUTICORIN 31-Mar-91 210 STATE THERMAL COAL OIL No
METTUR 4-Jan-87 210 STATE THERMAL COAL OIL No
METTUR 1-Dec-87 210 STATE THERMAL COAL OIL No
METTUR 22-Mar-89 210 STATE THERMAL COAL OIL No
METTUR 16-Feb-90 210 STATE THERMAL COAL OIL No
NORTH CHENNAI 25-Oct-94 210 STATE THERMAL COAL OIL No
NORTH CHENNAI 27-Mar-95 210 STATE THERMAL COAL OIL No
NORTH CHENNAI 24-Feb-96 210 STATE THERMAL COAL OIL No
VALUTHUR GT 246 STATE THERMAL GAS n/a No
P.NALLUR CCGT 22-Feb-01 330.5 PVT THERMAL GAS NAPT No
NEYVELI ST II 17-Jan-88 210 CENTER THERMAL LIGN OIL No
NEYVELI ST II 6-Feb-87 210 CENTER THERMAL LIGN OIL No
NEYVELI ST II 29-Mar-86 210 CENTER THERMAL LIGN OIL No
NEYVELI ST II 30-Mar-91 210 CENTER THERMAL LIGN OIL No
NEYVELI ST II 30-Dec-91 210 CENTER THERMAL LIGN OIL No
NEYVELI ST II 30-Oct-92 210 CENTER THERMAL LIGN OIL No
NEYVELI ST II 19-Jun-93 210 CENTER THERMAL LIGN OIL No
NEYVELI FST EXT 21-Oct-02 210 CENTER THERMAL LIGN OIL No
NEYVELI FST EXT 22-Jul-03 210 CENTER THERMAL LIGN OIL No
NEYVELI TPS(Z) 11-Oct-02 250 PVT THERMAL LIGN OIL No
VEMAGIRI CCCP 13-Jan-06 388.5 PVT THERMAL GAS n/a
Yes
(Ref
no:
4334)
BELLARY TPS 3-Dec-07 500 STATE THERMAL COAL OIL No
VIJAYWADA TPP-IV 8-Oct-09 500 STATE THERMAL COAL OIL No
GAUTAMI CCCP 468.57 PVT THERMAL GAS
Yes
(Ref
no:
4828)
TORANGALLU EXT 27-Apr-09 300 PVT THERMAL COAL OIL No
TORANGALLU EXT 24-Aug-09 300 PVT THERMAL COAL OIL No
KONASEEMA CCCP 31-Mar-09 445 PVT THERMAL GAS n/a No
KAKATIYA TPP 27-May-10 500 STATE THERMAL COAL OIL No
- - - - -
UNFCCC/CCNUCC
CDM – Executive Board Page 58
History of the document
Version Date Nature of revision
04.1 11 April 2012 Editorial revision to change version 02 line in history box from Annex 06 to Annex 06b.
04.0 EB 66 13 March 2012
Revision required to ensure consistency with the “Guidelines for completing the project design document form for CDM project activities” (EB 66, Annex 8).
03 EB 25, Annex 15 26 July 2006
02 EB 14, Annex 06b 14 June 2004
01 EB 05, Paragraph 12 03 August 2002
Initial adoption.
Decision Class: Regulatory
Document Type: Form
Business Function: Registration