PDD PGPL

UNFCCC/CCNUCC

CDM – Executive Board

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


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

http://www.powermin.nic.in/JSP_SERVLETS/internal.jsp

http://envfor.nic.in/divisions/ccd/cdm_iac.html

UNFCCC/CCNUCC


(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.

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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


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


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

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

http://www.cea.nic.in/reports/planning/cdm_co2/cdm_co2.htm

UNFCCC/CCNUCC


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


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


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


load

yes

3 Coal based power generation (Sub-critical

technology)


load

yes

4 Coal based power generation (Super-critical

technology)


load

yes

5 Lignite based power generation


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


load

yes

9 Electricity import from other grid


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

http://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

http://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

http://cercind.gov.in/160502/comp_bidding.pdf

http://cea.nic.in/thermal/Special_reports/Report%20of%20the%20committee%20to%20recommend%20next%20higher%20size%20of%20coal%20fired%20thermal%20power%20stations.pdf

http://cea.nic.in/thermal/Special_reports/Report%20of%20the%20committee%20to%20recommend%20next%20higher%20size%20of%20coal%20fired%20thermal%20power%20stations.pdf

UNFCCC/CCNUCC


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

http://energymanagertraining.com/kaupp/Article28.pdf

http://www.world-nuclear.org/info/inf53.html

UNFCCC/CCNUCC


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

http://cea.nic.in/reports/yearly/annual_rep/2009-10/ar_09_10.pdf

UNFCCC/CCNUCC


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


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


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


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

http://www.rbi.org.in/


http://powermin.nic.in/whats_new/competitive_guidelines.htm

UNFCCC/CCNUCC


Discount factor 11% http://www.rbi.org.in

ROE 16% Central Electricity Regulatory Commission (Terms


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


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


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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


A. Heat rate

Parameters -10% 0% 10%

Coal 1.87 2.00 2.13

Natural Gas 3.24 3.54 3.83

B. PLF


Coal 2.08 2.00 1.94

Natural Gas 3.60 3.54 3.49

C. Project cost


Coal 1.93 2.00 2.07

Natural Gas 3.48 3.54 3.59

D. Fuel cost


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


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


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


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


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


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.


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:


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


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.


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


Data / Parameter EFOM,y

Unit tCO2e/GWh

Description Operting Margin Emission Factor of NEWNE Grid






Choice of data

or

Measurement methods

and procedures




Additional comment

Data / Parameter NCV coal

Unit kCal/ Kg

Description Net calorific value of coal





Value(s) applied 3624.52 (GCV to NCV conversion done – 3755 kCal/kg /1.036 )

Choice of data

or

Measurement methods

and procedures




Additional comment



UNFCCC/CCNUCC


Data / Parameter EFCO2,coal

Unit tCO2/TJ

Description Carbon di oxide emission factor of coal.






Choice of data

or

Measurement methods

and procedures




Additional comment

Data / Parameter OXIDcoal

Unit -

Description Oxidation Factor of Coal






Choice of data

or

Measurement methods

and procedures



Purpose of data To estimate the CO2 emission co-efficient and to calculate the baseline

emission

Additional comment



UNFCCC/CCNUCC


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.


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


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

http://www.cercind.gov.in/

UNFCCC/CCNUCC


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


= 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


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


Data / Parameter EFBM,y

Unit tCO2e/GWh

Description Build Margin Emission Factor of NEWNE Grid



Power, Government of India. CO2 Baseline Database is a publicly

available national data, with high level of reliability.



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


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.


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


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


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


UNFCCC/CCNUCC


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




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.


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



monthly

QA/QC procedures The value will be crossed verified with the receipts raised by the power

distribution company as applicable.



UNFCCC/CCNUCC


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)


Measurement methods

and procedures


Recording Frequency: Recorded annually


Responsibility: CDM Manager will have the overall responsibility for

monitoring of this parameter.




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.




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)


Measurement methods

and procedures




Responsibility: CDM Manager will have the overall responsibility for

monitoring of this parameter.




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.




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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



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.




Monitoring frequency NA


Purpose of data To estimate emission reductions


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




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.




Monitoring frequency NA




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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




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.




Monitoring frequency As per requirement


Purpose of data To estimate leakage


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,

UNFCCC/CCNUCC


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.

UNFCCC/CCNUCC


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.

- - - - -

UNFCCC/CCNUCC


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

E-mail

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]

mailto:[email protected]

UNFCCC/CCNUCC


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.

UNFCCC/CCNUCC


Appendix 3: Applicability of selected methodology

Please refer section B.2 above

UNFCCC/CCNUCC


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


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.


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

UNFCCC/CCNUCC


FFj,k2 = Quantity of fuel type k2 (lignite) combusted in power plant j included in the

build margin

= 5672884 tonnes/year


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


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


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


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


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.

UNFCCC/CCNUCC


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


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

http://www.coal.nic.in/cpdanx.htm#Annexure-IV

http://www.nlcindia.com/about/about_01b.htm

UNFCCC/CCNUCC


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


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


Appendix 6: Summary of post registration changes

Not applicable

UNFCCC/CCNUCC


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 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 12-Oct-04 210 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



UNFCCC/CCNUCC


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 29-Jan-89 210 STATE THERMAL COAL OIL No



KOTA 25-Sep-88 210 STATE THERMAL COAL OIL No

UNFCCC/CCNUCC


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 1-Apr-89 210 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 26-Feb-84 200 CENTER THERMAL COAL OIL No

SINGRAULI STPS 23-Dec-86 500 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


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 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



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


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 31-May-87 500 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 27-Jul-06 500 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


UNFCCC/CCNUCC



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 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



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


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 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


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


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

PDD PGPL

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Transcript of PDD PGPL